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+10-K
+1
+d10k.txt
+ODETICS FORM 10-K FOR PERIOD ENDING 03/31/01
+--------------------------------------------------------------------------------
+--------------------------------------------------------------------------------
+UNITED STATES
+SECURITIES AND EXCHANGE COMMISSION
+Washington, D.C. 20549
+---------------
+FORM 10-K
+FOR ANNUAL AND TRANSITION REPORTS PURSUANT TO SECTIONS 13 OR 15(d)
+OF THE SECURITIES EXCHANGE ACT OF 1934
+(Mark One)
+[X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
+OF 1934
+For the fiscal year ended March 31, 2001
+OR
+[_]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
+ACT OF 1934
+For the transition period from to
+Commission file number 000-10605
+---------------
+ODETICS, INC.
+(Exact Name of Registrant as Specified in Its Charter)
+Delaware 95-2588496
+(State or Other Jurisdiction (I.R.S. Employer
+of Incorporation or Organization) Identification No.)
+1515 South Manchester Avenue, Anaheim, California 92802
+(Address of Principal Executive Offices) (Zip Code)
+Registrant's Telephone Number, Including Area Code: (714) 774-5000
+---------------
+Securities registered pursuant to Section 12(b) of the Act:
+None
+Securities registered pursuant to Section 12(g) of the Act:
+Class A common stock, $.10 par value
+Class B common stock, $.10 par value
+(Title of Class)
+---------------
+Indicate by check mark whether the registrant: (1) has filed all reports
+required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
+1934 during the preceding 12 months (or for such shorter period that the
+registrant was required to file such reports), and (2) has been subject to such
+filing requirements for the past 90 days. Yes [X] No [_]
+Indicate by a check mark if disclosure of delinquent filers pursuant to Item
+405 of Regulation S-K is not contained herein, and will not be contained, to
+the best of registrant's knowledge, in definitive proxy or information
+statements incorporated by reference in Part III of this Form 10-K or any
+amendment to this Form 10-K [_]
+Based on the closing sale price on Nasdaq National Market on June 21, 2001,
+the aggregate market value of the voting stock held by nonaffiliates of the
+registrant was $21,733,846. For the purposes of this calculation, shares owned
+by officers, directors and 10% stockholders known to the registrant have been
+deemed to be owned by affiliates. This determination of affiliate status is not
+necessarily a conclusive determination for other purposes.
+Odetics has two classes of common stock outstanding, the Class A common
+stock and the Class B common stock. The rights, preferences and privileges of
+each class of common stock are identical in all respects, except for voting
+rights. Each share of Class A common stock entitles its holder to one-tenth of
+one vote per share and each share of Class B common stock entitles its holder
+to one vote per share. As of June 21, 2001, there were 9,542,889 shares of
+Class A common stock and 1,035,841 shares of Class B common stock outstanding.
+Unless otherwise indicated, all references to common stock shall collectively
+refer to the Class A common stock and the Class B common stock
+DOCUMENTS INCORPORATED BY REFERENCE
+Part III incorporates certain information by reference from the registrant's
+definitive proxy statement for the annual meeting of the stockholders scheduled
+to be held on September 14, 2001.
+--------------------------------------------------------------------------------
+--------------------------------------------------------------------------------
+ODETICS, INC.
+FORM 10-K ANNUAL REPORT
+TABLE OF CONTENTS
+Page
+----
+PART I
+ITEM 1. BUSINESS...................................................... 1
+ITEM 2. PROPERTIES.................................................... 16
+ITEM 3. LEGAL PROCEEDINGS............................................. 16
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS........... 16
+PART II
+ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
+STOCKHOLDER MATTERS.......................................... 17
+ITEM 6. SELECTED FINANCIAL DATA....................................... 19
+ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
+AND RESULTS OF OPERATIONS.................................... 20
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK..... 25
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................... 25
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
+AND FINANCIAL DISCLOSURE..................................... 25
+PART III
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT............ 26
+ITEM 11. EXECUTIVE COMPENSATION........................................ 26
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
+MANAGEMENT................................................... 26
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS................ 26
+PART IV
+ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
+FORM 8-K..................................................... 27
+i
+Note: When used in this Annual Report on Form 10-K and the information
+incorporated herein by reference, the words "expect(s)," "feel(s),"
+"believe(s)," "will," "may," "anticipate(s)," and similar expressions are
+intended to identify forward-looking statement. Such statements are subject to
+certain risks and uncertainties which could cause actual results to differ
+materially from those projected. You should not place undue reliance on these
+forward-looking statements that speak only as of the date hereof. We undertake
+no obligation to republish revised forward-looking statements to reflect events
+or circumstances after the date hereof or to reflect the occurrence of
+unanticipated events. We encourage you to carefully review and consider the
+various disclosures made by us which describe certain factors which affect our
+business, including the risk factors set forth at the end of Part I, Item 1 of
+this report and in Part II, Item 7. "Management's Discussion and Analysis of
+Financial Condition and Results of Operations."
+PART I
+ITEM 1. BUSINESS
+General
+Odetics, Inc. was founded in 1969 to supply digital recorders for use in the
+United States space program. We pioneered new designs and standards for digital
+magnetic tape recorders offering high reliability and enhanced performance in
+the adverse environment attendant to space flight. In the 1970s, we broadened
+our information automation product line to include time-lapse videocassette
+recorders for commercial security and surveillance applications, and entered
+the business of manufacturing telecom network synchronization products. Through
+our Gyyr division, we became a leading supplier of time-lapse videotape
+cassette recorders, digital image processing modules and related products used
+in security and surveillance systems. We incorporated our Gyyr division in
+1997, forming a wholly-owned subsidiary, Gyyr Incorporated. In October 1997, we
+expanded Gyyr by acquiring Intelligent Controls Inc., a manufacturer of access
+control products specializing in PC based, remote site and fiber optic
+communications. In December 1999, we acquired the Security Products Division of
+Digital Systems Processing, Inc., which expanded our product line to include
+digital time-lapse recording based on hard disk drive technology.
+Beginning in the late 1970s, we developed and manufactured telecom
+synchronization products in our Communications division. We incorporated our
+Communications division in fiscal 1999 as our wholly-owned subsidiary, Zyfer,
+Inc., as part of our business expansion to develop products for secured
+communications over the Internet.
+Leveraging our expertise in video image processing, we entered into the
+intelligent transportation system ("ITS") business with the introduction of a
+video-based vehicle detection system in 1993. In June 1997, we acquired certain
+assets comprising the Transportation Systems business from Rockwell
+International, creating our ITS division, which expanded our offerings to
+include advanced traffic management systems and advanced traveler information
+systems. We incorporated our ITS division in 1998 as Odetics ITS, Inc. In
+October 1998, we broadened our systems offerings by acquiring Meyer, Mohaddes
+Associates, Inc. In January 2000, we reincorporated Odetics ITS in Delaware and
+changed its name to Iteris, Inc. Meyer, Mohaddes Associates, Inc. currently
+operates as a wholly-owned subsidiary of Iteris, Inc.
+In the early 1980s, we developed the technical expertise to apply automation
+to new commercial applications and established our Odetics Broadcast division.
+We incorporated our Odetics Broadcast division in 1999 as Broadcast, Inc.
+Broadcast develops and manufactures broadcast automation control systems. The
+success of our video tape libraries led us to pursue new applications for
+information automation technologies. In 1991, we introduced an automated tape
+handling subsystem for integration into tape libraries designed for midrange
+computers and client/server networks. In January 1993, we formed a separate
+subsidiary, ATL Products, Inc., to pursue the market for automated tape
+libraries. In March 1997, ATL completed an initial public offering of 1,650,000
+shares of its Class A common stock. We distributed our remaining 82.9% interest
+in ATL to our stockholders in a tax-free distribution in October 1997.
+1
+Today, Odetics serves as a developer of technology-oriented companies, each
+with its own marketplace, customers and products. These operations share a
+common corporate overhead for support for facilities, human resources, benefits
+and certain accounting, finance and executive management services. We are
+pursuing a business strategy to develop each of these business units with the
+ultimate goal of monetizing them for the benefit of our stockholders. While our
+strategy also embodies the tax-free spin-off of our developed companies to our
+stockholders, we cannot assure that we will be able to spin-off any of these
+companies in the near future, if at all.
+We currently define our business segments as video products, telecom
+products and ITS. Our video products segment includes our Broadcast subsidiary
+and our Gyyr subsidiary. Our telecom products segment includes our Zyfer
+subsidiary and our Mariner Networks subsidiary. Our ITS segment consists of our
+Iteris subsidiary. For more information concerning our business segments,
+please see Note 13 of Notes to Consolidated Financial Statements.
+Video Products
+Broadcast, Inc.
+Broadcast develops systems to automate the storage and scheduling of
+commercials, news stories and other television programming recorded on
+videotape and video server storage systems. We believe that enhanced
+operational efficiencies are a principal factor underlying the automation of
+broadcast television stations and satellite uplink operations as the industry
+transitions to digital television. During fiscal 2001, Broadcast began
+transitioning its focus from a hardware-based business to a product offering
+based on proprietary software solutions for broadband video content management
+and delivery to serve broadcast and cable operations.
+We offer software to form powerful integrated systems, including our
+AIRO(TM) automation system. Multi-channel presentation systems, which integrate
+the complete line of our hardware with commonly available broadcast quality
+video disk recorders, are quickly becoming the core business of Broadcast.
+Broadcast is focused on video asset management, including desktop video
+browsing using a network PC architecture, which can be extended to wide area
+network applications and Internet applications.
+Sales, Marketing and Principal Customers. Broadcast sells directly to
+broadcast television stations, satellite uplink operations, and other broadcast
+television and cable television system operators. The sales and marketing
+management for Broadcast is located at our principal facilities in Anaheim,
+California. Broadcast maintains a dedicated field sales force of three persons
+operating in three U.S. sales regions and Canada, and a sales manager for Latin
+America, Europe and Asia. Broadcast also utilizes additional independent
+representative organizations to promote its products in various other foreign
+markets.
+The customers of Broadcast include major television networks such as Fox,
+the Canadian Broadcasting Corporation, CNBC, Euronews, Televisa, Measat
+Broadcast Network Systems, NBC, the PBS Network, Group W Satellite
+Communications, Asia Broadcast Centre, Univision and over 100 independent and
+network-affiliated television stations. Broadcast currently has systems
+installed in over 40 countries.
+Manufacturing and Materials. Broadcast maintains a dedicated manufacturing
+operation located within our Anaheim, California facilities. Our AIRO products
+are serviced primarily in a facility located in Austin, Texas. At our Anaheim
+facility, Broadcast maintains infrastructure to support production and
+inventory control, purchasing, quality assurance, manufacturing and
+engineering.
+Broadcast purchases video servers from Grass Valley Group, Leitch and
+Pinnacle Systems and video switching, conversion and monitoring equipment from
+Grass Valley Group. Broadcast also purchases cabinets and other fabricated
+parts and components from other third party suppliers.
+2
+Gyyr Incorporated
+Gyyr produces analog and digital video products and access control systems
+that meet the security and surveillance needs for a variety of markets
+including banking, commercial/industrial and retail. Gyyr currently operates
+two divisions, Gyyr GCTV Products and Gyyr Electronic Access Controls. Gyyr
+GCTV Products develops and manufactures analog and digital video products and
+focuses on developing innovative solutions for digital storage assistance based
+video surveillance. Gyyr's time-lapse VCRs are installed in automated teller
+machines and retail point of sale systems to record transaction information in
+an effort to deter and address incidents of theft and other crimes. Gyyr
+Electronic Access Controls develops and manufactures enterprise security
+management systems and focuses on developing network-based access control
+products. Gyyr's access control systems offer managed access and monitoring of
+public, private and high security facilities. Customer demand for more
+sophisticated capabilities and integration due to digital technology has also
+contributed to the recent growth in the market for Gyyr's products. Gyyr's
+strategy is to provide complete software-based system integration of digital
+security devices over a variety of network topologies and the Internet. Recent
+additions to Gyyr's product offerings include network and Internet-based video
+and device control, and video multiplexing and digital recording. In December
+1999, we expanded our product line to include the DVMS family of digital time-
+lapse recorders based on hard disk drive architecture. This product line
+expansion was the result of our acquisition of the Security Products Division
+of Digital Systems Processing, Inc. We sell our products as individual devices
+as well as components of fully-integrated network security control systems.
+Sales, Marketing and Principal Customers. Gyyr markets and sells its
+products through three established channels: OEMs, independent distributors and
+system integrators. Gyyr personnel located at our principal facilities and
+sales offices throughout the world oversee approximately 1,000 of these channel
+partners. Gyyr has a business development and service organization located at
+our Odetics Europe Limited subsidiary. Through January 2000, Odetics Europe
+Limited assisted Gyyr with management in the development of European, Middle
+East and African markets. Commencing in January 2000, Gyyr formed Gyyr Europe
+Limited to succeed Odetics Europe Limited in its support services. Its Asian
+sales and marketing activities are managed from our Anaheim, California
+facilities. Gyyr's principal customers include major security equipment
+companies such as Diebold, Inc., ADT Security Systems, Inc., Honeywell, Inc.,
+Mosler, Inc., Hamilton Safe and ADI.
+Manufacturing and Materials. Gyyr maintains a dedicated manufacturing area
+located within our principal facilities in Anaheim, California. Gyyr primarily
+uses continuous demand flow techniques in its assembly lines. Gyyr maintains
+infrastructure to support production and inventory control, purchasing, quality
+assurance and manufacturing engineering.
+Gyyr purchases substantially all of its VCRs through Nissei Sangyo America,
+the United States distribution affiliate of Hitachi, Ltd., into which we
+incorporate certain value-added features. As a result of its reliance on
+Hitachi, Ltd, Gyyr is vulnerable to Hitachi's actions, which might necessitate
+changes in the design or manufacturing of Gyyr's products. While other
+suppliers are available who can manufacture VCRs suitable for use in Gyyr's
+products, we would be required to make changes in our product design or
+manufacturing methods to accommodate other VCRs, and Gyyr could experience
+delays or interruptions in supply while these changes are incorporated or a new
+supplier is procured.
+Telecom Products
+Zyfer, Inc.
+We incorporated our Communications division in 1999 as Zyfer, Inc. Zyfer
+develops and manufactures telecom network synchronization products and provides
+service support for space borne digital data recorders. Our telecom network
+synchronization products synchronize communications for data security, timing
+networks and wireless communications systems. These products are based on GPS
+and oscillator technologies and are sold for new applications in wireless
+networks and satellite communications for both commercial and government
+customers. Significant customers of Zyfer include the U.S. government,
+government subcontractors and LGIC of Korea.
+3
+Zyfer has developed a new class of encryption products for securing
+enterprise wide communications. These products provide transparent security to
+users and system administrators. Transparency results from the elimination of
+traditional key exchange and key management requirements and from our ability
+to encrypt and decrypt at high data rates.
+The space borne digital recorders serviced by Zyfer are employed in
+satellite programs for space research, earth resource and environmental
+observation and weather monitoring, as well as global surveillance and
+classified government programs.
+Sales, Marketing and Principal Customers. Zyfer conducts its selling and
+marketing activities directly from our principal facilities in Anaheim,
+California. Zyfer also sells its telecom synchronization products primarily
+through manufacturers' representatives.
+Manufacturing and Materials. Zyfer's manufacturing processes are ISO
+certified. Most of its manufacturing processes consist of final assembly and
+test. Zyfer outsources board assembly and some preliminary fabrication
+processes.
+Mariner Networks, Inc.
+Mariner Networks, Inc. has developed and manufactures a family of multi-
+service access devices that enable branch offices to cost effectively combine
+their separate voice, video and data networks onto a single wide area transport
+network. The Dexter(R) product family provides wire speed transport of most
+data traffic types. Mariner Networks' products include ATM, frame relay and
+voice subsystems for handling intranet, data, voice and video traffic.
+Sales, Marketing and Principal Customers. Mariner Networks sells its
+products through its direct sales organization and resellers in North America
+and in Europe. Mariner Networks maintains sales offices at our facilities in
+Anaheim, California and maintains a European subsidiary, Mariner Networks
+Europe Ltd., which occupies space within Odetics Europe Limited in the United
+Kingdom.
+Manufacturing and Materials. Mariner Networks' manufacturing processes are
+ISO 9000 certified and consist primarily of final assembly and test. Mariner
+Networks currently outsources circuit board assembly and some fabrication
+processes.
+ITS Products
+Iteris, Inc.
+Iteris, Inc. designs, develops, markets and implements software-based
+solutions that improve the safety and efficiency of vehicle transportation.
+Using its proprietary software and ITS industry expertise, Iteris provides
+video sensor systems and transportation management and traveler information
+systems for the ITS industry. The ITS industry is comprised of companies
+applying a variety of technologies to enable the safe and efficient movement of
+people and goods. Iteris uses its outdoor image recognition software expertise
+to develop proprietary algorithms for video sensor systems that improve vehicle
+safety and the flow of traffic. Our knowledge of the ITS industry enables
+Iteris to design and implement transportation solutions that help public
+agencies reduce traffic congestion and provide greater access to traveler
+information.
+Iteris' proprietary image recognition systems include AutoVue and Vantage.
+AutoVue is a small windshield mounted sensor that utilizes proprietary software
+to detect and warn drivers of unintended lane departures. Through new software
+development, Iteris is expanding the AutoVue platform to incorporate additional
+safety and convenience features. Vantage is a video vehicle sensing system that
+detects the presence of vehicles at signalized intersections enabling a more
+efficient allocation of green signal time.
+Iteris, Inc. designs, develops and implements software-based systems that
+integrate sensors, video surveillance, computers and advanced communications
+equipment enabling public agencies to monitor, control
+4
+and direct traffic flow, assist in the quick dispatch of emergency crews and
+distribute real-time information about traffic conditions.
+Sales, Marketing and Principal Customers. Iteris markets and sells its
+transportation management systems and services directly to government agencies
+pursuant to negotiated contracts which involve competitive bidding and specific
+qualification requirements. Sales of Iteris' systems generally involve long
+lead times and require extensive specification development, evaluation and
+price negotiations.
+Iteris sells its Vantage vehicle detection systems primarily through
+indirect sales channels comprised of independent dealers in the United States
+and Canada who sell integrated solutions and related products to the traffic
+intersection market. The independent dealers for Iteris are primarily
+responsible for sales, installation and support of Vantage systems. These
+dealers maintain an inventory of demonstration traffic products including the
+Vantage vehicle detection systems and sell directly to government agencies and
+installation contractors. These dealers often have long-term arrangements with
+the government agencies in their territory for the supply of various products
+for the construction and renovation of traffic intersections. Iteris holds
+technical training classes for its dealers and maintains a full-time staff of
+customer support technicians to provide technical assistance when needed.
+The marketing strategy for AutoVue is to establish it as the leading
+platform for in vehicle video sensing for trucks and passenger cars. AutoVue is
+sold directly by Iteris to vehicle manufacturers. Iteris currently has a direct
+sales force of two product managers, and intends to expand its sales force in
+the future to include engineers and product managers who will be responsible
+for sales and customer service to specific vehicle manufacturers. Since its
+target customer base is well known, Iteris currently does not plan to engage in
+broad-scale marketing campaigns.
+Manufacturing and Materials. Iteris designs, assembles and tests the
+components of its Vantage systems in approximately 5,000 square feet of space
+at our Anaheim facility. Production equipment consists of assembly lines and
+test apparatus for final assembly and testing of the manufactured product.
+Production volume is based upon quarterly forecasts that Iteris readjusts on a
+monthly basis to control inventory. Iteris subcontracts the manufacture of its
+AutoVue systems to two manufacturers. We anticipate these manufacturers will be
+able to produce unit volume sufficient to support sales to heavy truck
+manufacturers. Iteris intends to engage additional manufacturers with expertise
+in high volume production to produce higher volumes for light and medium trucks
+and passenger cars. Iteris does not manufacture any of the hardware used in the
+transportation management and traveler information systems that it designs and
+implements. The production facility for Iteris is ISO 9001 certified.
+Customer Support and Services
+Each of our business units is responsible for its own customer support and
+service organizations. We provide warranty service for each of our product
+lines, as well as follow-up service and support, for which we typically charge
+separately. We also offer separate software maintenance agreements to our
+customers. We view customer support services as a critical competitive factor
+as well as a revenue source.
+Backlog
+Our backlog of unfulfilled firm orders was approximately $31.0 million as of
+March 31, 2001 and approximately $27.3 million as of March 31, 2000.
+Approximately 70% of our backlog at March 31, 2000 was recognized as revenues
+in fiscal 2001, and approximately 68% of our backlog at March 31, 2001 is
+expected to be recognized as revenues in fiscal 2002. Pursuant to the customary
+terms of our agreements with government contractors and other customers,
+customers can generally cancel or reschedule orders with little or no
+penalties. Lead times for the release of purchase orders depend upon the
+scheduling and forecasting practices of our individual customers, which also
+can affect the timing of the conversion of our backlog into revenues. For these
+reasons, among others, our backlog at a particular date may not be indicative
+of our future revenues.
+5
+Product Development
+Each of our business units directs and staffs its own product development
+activities. Most of our development activities are conducted at our principal
+facilities in Anaheim, California. Mariner Networks also maintains a
+development team in La Gaude, France.
+Our business units require substantial ongoing research and development
+expenditures and other product development activities. Our company-sponsored
+research and development costs and expenses were approximately $11.2 million in
+fiscal 1999, $16.9 million in fiscal 2000 and $18.8 in fiscal 2001. We expect
+to continue to pursue significant product development programs and incur
+significant research and development expenditures in each of our business
+units.
+Competition
+Our business units generally face significant competition in each of their
+respective markets. Increased competition may result in price reductions,
+reduced gross margins and loss of market share, any of which could have a
+material adverse effect on our business, financial condition and results of
+operations.
+Broadcast's primary competitors include Sony, Harris, Encoda and Probel.
+Sony is a large, international supplier of extensive professional quality
+products, including video tape libraries, for the broadcast television market.
+Harris and Probel principally provide automation control for video libraries
+and disk recorders. Broadcast's systems compete primarily in the arena of
+facility management and enterprise wide automation. We believe that the
+capability of our systems to integrate the broadcast station business systems
+acquisition processes, storage devices and presentation devices under a
+relational data base management system represents a unique and differentiable
+capability.
+As Gyyr expands its product base from time-lapse VCRs to providing
+integrated security systems in CCTV and electronic access control, it will
+compete with a broader set of companies. Major Japanese competitors in Gyyr's
+legacy tape-based time-lapse VCR business include Panasonic, Toshiba, Sony,
+Sanyo, Mitsubishi and JVC. Gyyr also competes with large systems suppliers
+including Sensormatic, Honeywell, Pelco, Ultrak, Ademco and Vicon. In the sale
+of access control systems, Gyyr principally competes with Casi-Rusco,
+Checkpoint, Cardkey and Lenel. Gyyr generally competes based upon its strength
+in the integration of its various component products into systems that provide
+complete solutions through the use of advanced software and networking
+technologies.
+Zyfer's primary competition for network synchronization products is Datum,
+Inc. and TrueTime Inc. Zyfer anticipates that its competition for encryption
+products for secured communications systems will include Cylink Corporation,
+Rainbow Technologies, Inc. and Redcreek Communications Inc. The competition for
+integrated circuits addressing encryption applications include Broadcom
+Corporation, Chrysalis and HiFN.
+Mariner Networks' principal competition includes networking vendors Vina
+Technologies, Accelerated Networks, Marconi and Nortel Networks.
+While we believe that AutoVue is the only commercially-available lane
+departure warning system, potential competitors including Delphi Automotive
+Systems Corporation domestically, NEC Corporation and Hitachi Ltd. in Japan and
+Robert Bosch Gmbh in Europe, which are currently developing video sensor
+technologies for the vehicle industry that could be used for lane departure
+warning systems. In the market for our Vantage vehicle detection systems, we
+compete with both manufacturers of "above ground" video camera detection
+systems, such as Econolite Control Products, Inc., Trafficon, N.V. and the Peek
+Traffic Systems division of Thermo Electron Corporation, and other non-
+intrusive detection devices including microwave, infrared, ultrasonic and
+magnetic detectors, as well as manufacturers and installers of in-pavement
+inductive loop products.
+The transportation management and traveler information systems market is
+highly fragmented and is subject to evolving national and regional quality and
+safety standards. Iteris' competitors vary in number, scope
+6
+and breadth of the products and services they offer. Iteris' competitors in
+advanced transportation management and traveler information systems include
+corporations such as TRW, Inc., Transcore, Lockheed Martin Corporation, PB
+Farradyne Inc., Kimley-Horn and Associates, Inc. and National Engineering
+Technology, Inc. Iteris' competitors in transportation engineering, planning
+and design include major firms such as Parsons Brinkerhoff, Inc. and Parsons
+Transportation Group Inc., as well as many regional engineering firms.
+In general, the markets for the products and services offered by our
+businesses are highly competitive and are characterized by rapidly changing
+technology and evolving standards. Many of our current and prospective
+competitors have longer operating histories, greater name recognition, access
+to larger customer bases and significantly greater financial, technical,
+manufacturing, distribution and marketing resources than us. As a result, they
+may be able to adapt more quickly to new or emerging standards or technologies
+or to devote greater resources to the promotion and sale of their products. It
+is also possible that new competitors or alliances among competitors could
+emerge and rapidly acquire significant market share. We believe that our
+ability to compete effectively in our target markets depends on a number of
+factors, including the success and timing of our new product development, the
+compatibility of our products with a broad range of computing systems, product
+quality and performance, reliability, functionality, price, and service and
+technical support. Our failure to provide services and develop and market
+products that compete successfully with those of other suppliers and
+consultants in our target markets would have a material adverse effect on our
+business, financial condition and results of operations.
+Intellectual Property and Proprietary Rights
+Our ability to compete effectively depends in part on our ability to develop
+and maintain the proprietary aspects of our technology. Our policy is to obtain
+appropriate proprietary rights protection for any potentially significant new
+technology acquired or developed each of our business units. We currently hold
+a number of United States and foreign patents and trademarks, which will expire
+at various dates commencing in 2004. We also have pending a number of United
+States and foreign patent applications relating to certain of our products;
+however, we cannot be certain that any patents will be granted pursuant to
+these applications.
+In addition to patent laws, we rely on copyright and trade secret laws to
+protect our proprietary rights. We attempt to protect our trade secrets and
+other proprietary information through agreements with customers and suppliers,
+proprietary information agreements with our employees and consultants, and
+other similar measures. We cannot be certain that we will be successful in
+protecting our proprietary rights. While we believe our patents, patent
+applications, software and other proprietary know-how have value, changing
+technology makes our future success dependent principally upon our employees'
+technical competence and creative skills for continuing innovation.
+Litigation has been necessary in the past and may be necessary in the future
+to enforce our proprietary rights, to determine the validity and scope of the
+proprietary rights of others, or to defend us against claims of infringement or
+invalidity by others. An adverse outcome in such litigation or similar
+proceedings could subject us to significant liabilities to third parties,
+require disputed rights to be licensed from others or require us to cease
+marketing or using certain products, any of which could have a material adverse
+effect on our business, financial condition and results of operations. In
+addition, the cost of addressing any intellectual property litigation claim,
+both in legal fees and expenses, as well as from the diversion of management's
+resources, regardless of whether the claim is valid, could be significant and
+could have a material adverse effect on our business, financial condition and
+results of operations.
+Employees
+We refer to our employees as associates. As of June 20, 2001, we employed
+442 associates, including 72 associates in general management, administration
+and finance; 65 associates in sales and marketing; 170 associates in product
+development; 105 associates in operations, manufacturing and quality; and
+30 associates in customer service. None of our associates are represented by a
+labor union and we have not experienced a work stoppage.
+7
+We provide centralized support for human resources management for each of
+our business units and subsidiaries. These services include recruiting,
+administration and outplacement.
+Government Regulation
+Our manufacturing operations are subject to various federal, state and local
+laws, including those restricting the discharge of materials into the
+environment. We are not involved in any pending or threatened proceedings which
+would require curtailment of our operations because of such regulations. We
+continue to expend funds in connection with our compliance with applicable
+environmental regulations. These expenditures have not, however, been
+significant in the past, and we do not expect any significant expenditures in
+the near future.
+From time to time, a portion of our work relating to network synchronization
+systems may constitute classified United States government information or may
+be used in classified programs of the United States Government. For this
+purpose, we possess certain relevant security clearances. Our affected
+facilities and operations are also subject to security regulations of the
+United States Government. We believe we are currently in full compliance with
+these regulations.
+8
+RISK FACTORS
+Our business is subject to a number of risks, some of which are discussed
+below. Other risks are presented elsewhere in this report. You should consider
+the following risks carefully in addition to the other information contained in
+this report before purchasing the shares of our common stock. If any of the
+following risks actually occur, they could seriously harm our business,
+financial condition or results of operations. In such case, the trading price
+of our common stock could decline, and you may lose all or part of your
+investment.
+We Have Experienced Substantial Losses and Expect Future Losses. We
+experienced significant operating losses of $49.8 million for the year ended
+March 31, 2001, $38.7 million for the year ended March 31, 2000 and $18.3
+million for the year ended March 31, 1999. In January 2001, we announced the
+reorganization of our business in order to reduce our operating expenses and
+negative cash flow, which included the downsizing of our operations in Gyyr and
+Broadcast, and a 25% reduction in our total work force. We cannot assure you
+that this reorganization will improve our financial performance, or that we
+will be able to achieve profitability on a quarterly or annual basis in the
+future. Most of our expenses are fixed in advance, and we generally are unable
+to reduce our expenses significantly in the short-term to compensate for any
+unexpected delay or decrease in anticipated revenues. As a result, we may
+continue to experience losses, which could cause the market price of our common
+stock to decline.
+We Will Need to Raise Additional Capital in the Future and May Not Be Able
+to Secure Adequate Funds on Terms Acceptable to Us, or at All. Our line of
+credit facility expired on December 31, 2000. While we have received an
+extension on this facility until July 31, 2001, we will need to obtain a new
+line of credit from another lender in the near future. Substantially all of our
+assets have been pledged to our existing lender to secure the outstanding
+indebtedness under this facility ($13.5 million at March 31, 2001). We cannot
+assure you that we will be able to obtain a new line of credit on a timely
+basis, on acceptable terms, or at all. Even if we are able to secure a new line
+of credit, we anticipate that we will need to raise additional capital in the
+near future, either through additional bank borrowings, the monetization of
+certain real property, the divestiture of business units or select assets, or
+other debt or equity financings. These conditions, together with our recurring
+losses, raise substantial doubt about our ability to continue as a going
+concern.
+Our capital requirements will depend on many factors, including:
+. our ability to control costs;
+. increased research and development funding, and required investments in
+our business units;
+. our ability to generate operating income;
+. market acceptance of our products;
+. technological advancements and our competitors' response to our
+products;
+. capital improvements to new and existing facilities;
+. increased sales and marketing expenses;
+. potential acquisitions of businesses and product lines; and
+. additional working capital needs.
+If our capital requirements are materially different from those currently
+planned, we may need additional capital sooner than anticipated. If additional
+funds are raised through the issuance of equity securities, the percentage
+ownership of our stockholders will be reduced and such securities may have
+rights, preferences and privileges senior to our common stock. Additional
+financing may not be available on favorable terms or at all. If adequate funds
+are not available or are not available on acceptable terms, we may be unable to
+develop or enhance our products, expand our sales and marketing programs, take
+advantage of future opportunities or respond to competitive pressures.
+9
+Our Quarterly Operating Results Fluctuate as a Result of Many Factors. Our
+quarterly revenues and operating results have fluctuated and are likely to
+continue to vary from quarter to quarter due to a number of factors, many of
+which are not within our control. Factors that could affect our revenues
+include, among others, the following:
+. our significant investment in research and development for our
+subsidiaries and business units;
+. our ability to control costs;
+. our ability to develop, introduce, market and gain market acceptance of
+new products applications and product enhancements in a timely manner;
+. the size, timing, rescheduling or cancellation of significant customer
+orders;
+. the introduction of new products by competitors;
+. the availability of components used in the manufacture of our products;
+. changes in our pricing policies and the pricing policies by our
+suppliers and competitors, pricing concessions on volume sales, as well
+as increased price competition in general;
+. the long lead times associated with government contracts or required by
+vehicle manufacturers;
+. our success in expanding and implementing our sales and marketing
+programs;
+. the effects of technological changes in our target markets;
+. our relatively small level of backlog at any given time;
+. the mix of sales among our business units;
+. deferrals of customer orders in anticipation of new products,
+applications or product enhancements;
+. the risks inherent in our acquisitions of technologies and businesses;
+. risks and uncertainties associated with our international business;
+. currency fluctuations and our ability to get currency out of certain
+foreign countries; and
+. general economic and market conditions.
+In addition, our sales in any quarter may consist of a relatively small
+number of large customer orders. As a result, the timing of a small number of
+orders may impact our quarter to quarter results. The loss of or a substantial
+reduction in orders from any significant customer could seriously harm our
+business, financial condition and results of operations.
+Due to all of the factors listed above and other risks discussed in this
+report, our future operating results could be below the expectations of
+securities analysts or investors. If that happens, the trading price of our
+common stock could decline. As a result of these quarterly variations, you
+should not rely on quarter-to-quarter comparisons of our operating results as
+an indication of our future performance.
+Our Operating Strategy for Developing Companies is Expensive and May Not Be
+Successful. Our business strategy entails intensive business development
+activities, which are expensive and highly risky. The goal of this strategy is
+to develop companies that can be spun-off to our stockholders. This strategy
+has in the past required us to make significant investments in our business
+units, both for research and development, and also to develop a separate
+infrastructure for certain of our business units, sufficient to allow the unit
+to function as an independent public company. We expect to continue to invest
+in the development of certain of our business units with the goal of obtaining
+additional capital to support further investment and eventually completing
+additional public offerings. We may not recognize the benefits of this
+investment for a significant
+10
+period of time, if at all. Our ability to complete private financings or an
+initial public offering of any of our business units and/or spin-off our
+interest to our stockholders will depend upon many factors, including:
+. the overall performance and results of operations of the particular
+business unit;
+. the potential market for our business unit;
+. our ability to assemble and retain a broad, qualified management team
+for the business unit;
+. our financial position and cash requirements;
+. the business unit's customer base and product line;
+. the current tax treatment of spin-off transactions and our ability to
+obtain favorable determination letters from the Internal Revenue
+Service; and
+. general economic and market conditions, including the receptiveness of
+the stock markets to initial public offerings.
+We may not be able to complete a successful private or public offering or
+spin-off of any of our business units in the near future, or at all. During
+fiscal 2001, we attempted to complete the initial public offering of Iteris. We
+withdrew the offering due to adverse market conditions. Even if we do complete
+additional public offerings, we may decide not to spin-off a particular
+business unit, or to delay the spin-off until a later date.
+We Must Keep Pace with Rapid Technological Change to Remain Competitive. Our
+target markets are in general characterized by the following factors:
+. rapid technological advances;
+. downward price pressure in the marketplace as technologies mature;
+. changes in customer requirements;
+. frequent new product introductions and enhancements; and
+. evolving industry standards and changes in the regulatory environment.
+Our future success will depend upon our ability to anticipate and adapt to
+changes in technology and industry standards, and to effectively develop,
+introduce, market and gain broad acceptance of new products and product
+enhancements incorporating the latest technological advancements.
+We believe that we must continue to make substantial investments to support
+ongoing research and development in order to remain competitive. We need to
+continue to develop and introduce new products that incorporate the latest
+technological advancements in hardware, storage media, operating system
+software and applications software in response to evolving customer
+requirements. Our business and results of operations could be adversely
+affected if we do not anticipate or respond adequately to technological
+developments or changing customer requirements. We cannot assure you that any
+such investments in research and development will lead to any corresponding
+increase in revenue.
+Our Future Success Depends on the Successful Development and Market
+Acceptance of New Products. We believe our revenue growth and future operating
+results will depend on our ability to complete development of new products and
+enhancements, introduce these products in a timely, cost-effective manner,
+achieve broad market acceptance of these products and enhancements, and reduce
+our product costs. We may not be able to introduce any new products or any
+enhancements to our existing products on a timely basis, or at all. In
+addition, the introduction of any new products could adversely affect the sales
+of our certain of our existing products.
+Our future success will also depend in part on the success of several
+recently introduced products including DVMS, our family of digital time-lapse
+recorders; AutoVue, our lane departure warning system; and Dexter, our multi-
+service access device.
+11
+Market acceptance of our new products depends upon many factors, including
+our ability to accurately predict market requirements and evolving industry
+standards, our ability to resolve technical challenges in a timely and cost-
+effective manner and achieve manufacturing efficiencies, the perceived
+advantages of our new products over traditional products and the marketing
+capabilities of our independent distributors and strategic partners. Our
+business and results of operations could be seriously harmed by any significant
+delays in our new product development. We have experienced delays in the past
+in the introduction of new products, particularly with our Roswell system,
+which we recently discontinued. Certain of our new products could contain
+undetected design faults and software errors or "bugs" when first released by
+us, despite our testing. We may not discover these faults or errors until after
+a product has been installed and used by our customers. Any faults or errors in
+our existing products or in any new products may cause delays in product
+introduction and shipments, require design modifications or harm customer
+relationships, any of which could adversely affect our business and competitive
+position.
+We currently outsource the manufacture of our AutoVue product line to a
+single manufacturer. This manufacturer may not be able to produce sufficient
+quantities of this product in a timely manner or at a reasonable cost, which
+could materially and adversely affect our ability to launch or gain market
+acceptance of AutoVue.
+We Have Significant International Sales and Are Subject to Risks Associated
+with Operating in International Markets. International product sales
+represented approximately 20% of our total net sales and contract revenues for
+the fiscal year ended March 31, 2001, approximately 19% for the fiscal year
+ended March 31, 2000 and approximately 27% for the fiscal year ended March 31,
+1999. International business operations are subject to inherent risks,
+including, among others:
+. unexpected changes in regulatory requirements, tariffs and other trade
+barriers or restrictions;
+. longer accounts receivable payment cycles;
+. difficulties in managing and staffing international operations;
+. potentially adverse tax consequences;
+. the burdens of compliance with a wide variety of foreign laws;
+. import and export license requirements and restrictions of the United
+States and each other country in which we operate;
+. exposure to different legal standards and reduced protection for
+intellectual property rights in some countries;
+. currency fluctuations and restrictions; and
+. political, social and economic instability.
+We believe that international sales will continue to represent a significant
+portion of our revenues, and that continued growth and profitability may
+require further expansion of our international operations. Many of our
+international sales are currently denominated in U.S. dollars. As a result, an
+increase in the relative value of the dollar could make our products more
+expensive and potentially less price competitive in international markets. We
+do not engage in any transactions as a hedge against risks of loss due to
+foreign currency fluctuations.
+Any of these factors may adversely effect our future international sales
+and, consequently, on our business and operating results. Furthermore, as we
+increase our international sales, our total revenues may also be affected to a
+greater extent by seasonal fluctuations resulting from lower sales that
+typically occur during the summer months in Europe and other parts of the
+world.
+We Need to Manage Growth and the Integration of Our Acquisitions. Over the
+past few years, we have expanded our operations and made several substantial
+acquisitions of diverse businesses, including Intelligent
+12
+Controls, Inc., International Media Integration Services, Ltd., Meyer Mohaddes
+Associates, Inc., Viggen Corporation, certain assets of the Transportation
+Systems business of Rockwell International, and the Security Products Division
+of Digital Systems Processing, Inc. A key element of our business strategy
+involves expansion through the acquisition of complementary businesses,
+products and technologies. Acquisitions may require significant capital
+infusions and, in general, acquisitions also involve a number of special risks,
+including:
+. potential disruption of our ongoing business and the diversion of our
+resources and management's attention;
+. the failure to retain or integrate key acquired personnel;
+. the challenge of assimilating diverse business cultures, and the
+difficulties in integrating the operations, technologies and information
+system of the acquired companies;
+. increased costs to improve managerial, operational, financial and
+administrative systems and to eliminate duplicative services;
+. the incurrence of unforeseen obligations or liabilities;
+. potential impairment of relationships with employees or customers as a
+result of changes in management; and
+. increased interest expense and amortization of acquired intangible
+assets.
+Acquisitions may also materially and adversely affect our operating results
+due to large write-offs, contingent liabilities, substantial depreciation,
+deferred compensation charges or goodwill amortization, or other adverse tax or
+audit consequences.
+Our competitors are also soliciting potential acquisition candidates, which
+could both increase the price of any acquisition targets and decrease the
+number of attractive companies available for acquisition. We cannot assure you
+that we will be able to consummate any additional acquisitions, successfully
+integrate any acquisitions or realize the benefits anticipated from any
+acquisition.
+Acquisitions, combined with the expansion of our business units and recent
+growth has placed and is expected to continue to place a significant strain on
+our resources. To accommodate this growth, we anticipate that we will be
+required to implement a variety of new and upgraded operational and financial
+systems, procedures and controls, including the improvement of our accounting
+and other internal management systems. All of these updates will require
+substantial additional expense as well as management effort. Our failure to
+manage growth and integrate our acquisitions successfully could adversely
+affect our business, financial condition and results of operations.
+We Depend on Government Contracts and Subcontracts and Face Additional Risks
+Related to Fixed Price Contracts. A significant portion of the sales by Iteris
+and a portion of our sales by Zyfer were derived from contracts with
+governmental agencies, either as a general contractor, subcontractor or
+supplier. Government contracts represented approximately 25% and 26% of our
+total net sales and contract revenues for the years ended March 31, 2000 and
+2001, respectively. We anticipate that revenue from government contracts will
+continue to increase in the near future. Government business is, in general,
+subject to special risks and challenges, including:
+. long purchase cycles;
+. competitive bidding and qualification requirements;
+. performance bond requirements;
+. delays in funding, budgetary constraints and cut-backs; and
+. milestone requirements and liquidated damage provisions for failure to
+meet contract milestones.
+13
+In addition, a large number of our government contracts are fixed price
+contracts. As a result, we may not be able to recover for any cost overruns.
+These fixed price contracts require us to estimate the total project cost based
+on preliminary projections of the project's requirements. The financial
+viability of any given project depends in large part on our ability to estimate
+these costs accurately and complete the project on a timely basis. In the event
+our costs on these projects exceed the fixed contractual amount, we will be
+required to bear the excess costs. These additional costs adversely affect our
+financial condition and results of operations. Moreover, certain of our
+government contracts are subject to termination or renegotiation at the
+convenience of the government, which could result in a large decline in our net
+sales in any given quarter. Our inability to address any of the foregoing
+concerns or the loss or renegotiation of any material government contract could
+seriously harm our business, financial condition and results of operations.
+The Markets in Which We Operate Are Highly Competitive and Have Many More
+Established Competitors. We compete with numerous other companies in our target
+markets and we expect such competition to increase due to technological
+advancements, industry consolidations and reduced barriers to entry. Increased
+competition is likely to result in price reductions, reduced gross margins and
+loss of market share, any of which could seriously harm our business, financial
+condition and results of operations. Many of our competitors have far greater
+name recognition and greater financial, technological, marketing and customer
+service resources than we do. This may allow them to respond more quickly to
+new or emerging technologies and changes in customer requirements. It may also
+allow them to devote greater resources to the development, promotion, sale and
+support of their products than we can. Recent consolidations of end users,
+distributors and manufacturers in our target markets have exacerbated this
+problem. As a result of the foregoing factors, we may not be able to compete
+effectively in our target markets and competitive pressures could adversely
+affect our business, financial condition and results of operations.
+We Cannot Be Certain of Our Ability to Attract and Retain Key Personnel and
+We Do Not Have Employment Agreements with Any Key Personnel. Due to the
+specialized nature of our business, we are highly dependent on the continued
+service of our executive officers and other key management, engineering and
+technical personnel, particularly Joel Slutzky, our Chief Executive Officer and
+Chairman of the Board, and Gregory A. Miner, our Chief Operating Officer and
+Chief Financial Officer. We do not have any employment contracts with any of
+our officers or key employees. The loss of any of these persons would seriously
+harm our development and marketing efforts, and would adversely affect our
+business. Our success will also depend in large part upon our ability to
+continue to attract, retain and motivate qualified engineering and other highly
+skilled technical personnel. Competition for employees, particularly
+development engineers, is intense. We may not be able to continue to attract
+and retain sufficient numbers of such highly skilled employees. Our inability
+to attract and retain additional key employees or the loss of one or more of
+our current key employees could adversely affect upon our business, financial
+condition and results of operations.
+We May Not be Able to Adequately Protect or Enforce Our Intellectual
+Property Rights. If we are not able to adequately protect or enforce the
+proprietary aspects of our technology, competitors could be able to access our
+proprietary technology and our business, financial condition and results of
+operations will likely be seriously harmed. We currently attempt to protect our
+technology through a combination of patent, copyright, trademark and trade
+secret laws, employee and third party nondisclosure agreements and similar
+means. Despite our efforts, other parties may attempt to disclose, obtain or
+use our technologies or solutions. Our competitors may also be able to
+independently develop products that are substantially equivalent or superior to
+our products or design around our patents. In addition, the laws of some
+foreign countries do not protect our proprietary rights as fully as do the laws
+of the United States. As a result, we may not be able to protect our
+proprietary rights adequately in the United States or abroad.
+From time to time, we have received notices that claim we have infringed
+upon the intellectual property of others. Even if these claims are not valid,
+they could subject us to significant costs. We have engaged in litigation in
+the past, and litigation may be necessary in the future to enforce our
+intellectual property rights or to determine the validity and scope of the
+proprietary rights of others. Litigation may also be necessary to defend
+against claims of infringement or invalidity by others. An adverse outcome in
+litigation or any similar
+14
+proceedings could subject us to significant liabilities to third parties,
+require us to license disputed rights from others or require us to cease
+marketing or using certain products or technologies. We may not be able to
+obtain any licenses on terms acceptable to us, or at all. We also may have to
+indemnify certain customers or strategic partners if it is determined that we
+have infringed upon or misappropriated another party's intellectual property.
+Any of these results could adversely affect on our business, financial
+condition and results of operations. In addition, the cost of addressing any
+intellectual property litigation claim, both in legal fees and expenses, and
+the diversion of management resources, regardless of whether the claim is
+valid, could be significant and could seriously harm our business, financial
+condition and results of operations.
+The Trading Price of Our Common Stock Is Volatile. The trading price of our
+common stock has been subject to wide fluctuations in the past. Since January
+2000, our Class A common stock has traded at prices as low as $1.88 per share
+and as high as $29.44 per share. We may not be able to increase or sustain the
+current market price of our common stock in the future. As such, you may not be
+able to resell your shares of common stock at or above the price you paid for
+them. The market price of our common stock could continue to fluctuate in the
+future in response to various factors, including, but not limited to:
+. quarterly variations in operating results;
+. our ability to control costs and improve cash flow;
+. shortages announced by suppliers;
+. announcements of technological innovations or new products by our
+competitors, customers or us;
+. acquisitions or businesses, products or technologies;
+. changes in pending litigation or new litigation;
+. changes in investor perceptions;
+. our ability to spin-off any business unit;
+. applications or product enhancements by us or by our competitors; and
+. changes in earnings estimates or investment recommendations by
+securities analysts.
+The stock market in general has recently experienced volatility, which has
+particularly affected the market prices of equity securities of many high
+technology companies. This volatility has often been unrelated to the operating
+performance of these companies. These broad market fluctuations may adversely
+affect the market price of our common stock. In the past, companies that have
+experienced volatilities in the market price of their securities have been the
+subject of securities class action litigation. If we were to become the subject
+of a class action lawsuit, it could result in substantial losses and divert
+management's attention and resources from other matters.
+We Are Controlled by Certain of Our Officers and Directors. As of June 21,
+2001, our officers and directors beneficially owned approximately 28% of the
+total combined voting power of the outstanding shares of our Class A common
+stock and Class B common stock. As a result of their stock ownership, our
+management will be able to significantly influence the election of our
+directors and the outcome of corporate actions requiring stockholder approval,
+such as mergers and acquisitions, regardless of how our other stockholders may
+vote. This concentration of voting control may have a significant effect in
+delaying, deferring or preventing a change in our management or change in
+control and may adversely affect the voting or other rights of other holders of
+common stock.
+Our Stock Structure and Certain Anti-Takeover Provisions May Affect the
+Price of Our Common Stock. Certain provisions of our certificate of
+incorporation and our stockholder rights plan could make it difficult for a
+third party to acquire us, even though an acquisition might be beneficial to
+our stockholders. These provisions could limit the price that investors might
+be willing to pay in the future for shares of our common stock. Our Class A
+common stock entitles the holder to one-tenth of one vote per share and our
+15
+Class B common stock entitles the holder to one vote per share. The disparity
+in the voting rights between our common stock, as well as our insiders'
+significant ownership of the Class B common stock, could discourage a proxy
+contest or make it more difficult for a third party to effect a change in our
+management and control. In addition, our Board of Directors is authorized to
+issue, without stockholder approval, up to 2,000,000 shares of preferred stock
+with voting, conversion and other rights and preferences superior to those of
+our common stock, as well as additional shares of Class B common stock. Our
+future issuance of preferred stock or Class B common stock could be used to
+discourage an unsolicited acquisition proposal.
+In March 1998, we adopted a stockholder rights plan and declared a dividend
+of preferred stock purchase rights to our stockholders. In the event a third
+party acquires more than 15% of the outstanding voting control of our company
+or 15% of our outstanding common stock, the holders of these rights will be
+able to purchase the junior participating preferred stock at a substantial
+discount off of the then current market price. The exercise of these rights and
+purchase of a significant amount of stock at below market prices could cause
+substantial dilution to a particular acquiror and discourage the acquiror from
+pursuing our company. The mere existence of a stockholder rights plan often
+delays or makes a merger, tender offer or proxy contest more difficult.
+We Do Not Pay Cash Dividends. We have never paid cash dividends on our
+common stock and do not anticipate paying any cash dividends on either class of
+our common stock in the foreseeable future.
+We May Be Subject to Additional Risks. The risks and uncertainties described
+above are not the only ones facing our company. Additional risks and
+uncertainties not presently known to us or that we currently deem immaterial
+may also adversely affect our business operations.
+ITEM 2. PROPERTIES.
+Our headquarters and principal operations are located in Anaheim,
+California. In 1984, we purchased and renovated a three building complex
+containing approximately 257,900 square feet situated on approximately 14 acres
+adjacent to the Interstate 5 freeway, one block from Disneyland. Our facilities
+house our corporate and administrative offices (approximately 43,600 dedicated
+square feet), as well as the operations of Gyyr and Broadcast, (approximately
+113,400 dedicated square feet), Zyfer (approximately 56,300 dedicated square
+feet), Mariner Networks (approximately 20,600 dedicated square feet) and Iteris
+(approximately 24,000 dedicated square feet).
+Broadcast leases approximately 5,000 square feet in Austin, Texas primarily
+for service and sales support. Odetics Europe Limited's offices are located in
+leased space near London, England. Odetics Asia Pacific Pte. Ltd. offices are
+located in leased space in Singapore. Iteris leases eleven office suites
+representing an aggregate of approximately 35,000 square feet within the United
+States for its support staff and development teams.
+We currently operate a single shift in each of our manufacturing and
+assembly facilities, and we believe that our facilities are adequate for our
+current needs and for possible future growth. We may, however, elect to expand
+or relocate its offices and facilities in the future.
+ITEM 3. LEGAL PROCEEDINGS.
+None.
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
+None.
+16
+PART II
+ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
+Our Class A common stock and Class B common stock are traded on the Nasdaq
+National Market under the symbols "ODETA" and "ODETB," respectively. The
+following table sets forth for the fiscal periods indicated the high and low
+sales prices for the Class A common stock and Class B common stock as reported
+by the Nasdaq National Market:
+Class A Class B
+Common Stock Common Stock
+------------- -------------
+High Low High Low
+------ ------ ------ ------
+Fiscal Year Ended March 31, 2000
+First Quarter.................................... $10.25 $ 7.63 $10.63 $ 8.25
+Second Quarter................................... 13.00 9.13 12.13 9.13
+Third Quarter.................................... 15.50 10.13 15.63 10.38
+Fourth Quarter................................... 29.44 12.00 29.63 13.00
+Fiscal Year Ended March 31, 2001
+First Quarter.................................... 15.25 7.88 15.00 10.00
+Second Quarter................................... 17.94 13.00 17.63 13.50
+Third Quarter.................................... 17.00 5.53 17.00 5.63
+Fourth Quarter................................... 8.00 2.94 8.25 3.00
+Fiscal Year Ending March 31, 2002
+First Quarter (through June 21, 2001)............ 4.60 1.88 4.64 2.95
+As of June 21, 2001, we had 556 holders of record of Class A common stock
+and 127 holders of record of Class B common stock according to information
+furnished by our transfer agent.
+Dividend Policy
+Pursuant to the terms of our Loan and Security Agreement with our lender, we
+are prohibited from paying any dividends on our common stock without our
+lender's consent. We have never paid or declared cash dividends on either class
+of our common stock, and have no current plans to pay such dividends in the
+foreseeable future. We currently intend to retain any earnings for working
+capital and general corporate purposes. The payment of any future dividends
+will be at the discretion of our Board of Directors, and will depend upon a
+number of factors, including, but not limited to, future earnings, the success
+of our business, activities, our capital requirements, our general financial
+condition and future prospects, general business conditions, the consent of our
+lender and such other factors as the Board may deem relevant.
+Recent Sales of Unregistered Securities
+During the last fiscal year, we have sold and issued the following
+unregistered securities:
+In October 1998, Iteris acquired Meyer, Mohaddes Associates, Inc. Pursuant
+to the terms of the merger agreement, and as a penalty for not completing the
+initial public offering of Iteris, we issued an aggregate of an additional
+38,995 shares of our Class A Common Stock in fiscal 2001 to the former
+shareholders of Meyer, Mohaddes.
+17
+In September 2000, we issued an aggregate of 1,199,815 shares of our Class A
+common stock to 24 accredited investors in a private placement at a purchase
+price of $14.26 per share or an aggregate purchase price of $17.1 million. B.
+Riley & Co. acted as a finder with respect to a portion of this offering.
+The sale and issuance of securities set forth above were deemed to be exempt
+from registration under the Securities Act by virtue of Section 4(2) thereof.
+The recipients of the securities in each of the transactions set forth in above
+represented their intention to acquire such securities for investment only and
+not with a view to or for sale in connection with any distribution thereof, and
+appropriate legends were affixed to the share certificates and instruments used
+in such transactions. Except as indicated above, there were no underwriters,
+brokers or finders employed in connection with any of the foregoing
+transactions.
+18
+ITEM 6. SELECTED FINANCIAL DATA.
+The following selected consolidated financial data with respect to our
+consolidated statement of operations for each of the five fiscal years in the
+period ended March 31, 2001 and the consolidated balance sheet data at March
+31, 1997, 1998, 1999, 2000 and 2001 are derived from our audited consolidated
+financial statements. The consolidated financial statements for the fiscal
+years ended March 31, 1997 and 1998 and our consolidated balance sheet at
+March 31, 1997, 1998 and 1999 are not included in this report. The following
+information should be read in conjunction with "Management's Discussion and
+Analysis of Financial Condition and Results of Operations" and with our
+consolidated financial statements and the related notes thereto included
+elsewhere in this report.
+Fiscal Year Ended March 31,
+-----------------------------------------------
+1997 1998 1999 2000 2001
+------- -------- -------- -------- --------
+(in thousands, except per share data)
+Consolidated Statement of
+Operations Data:
+Net sales.................... $71,748 $ 79,552 $ 70,042 $ 62,041 $ 57,030
+Contract revenues............ 9,032 10,284 13,331 18,666 20,039
+------- -------- -------- -------- --------
+Total net sales and contract
+revenues.................... 80,780 89,836 83,373 80,707 77,069
+Cost of sales................ 48,507 55,227 49,816 50,883 46,244
+Cost of contract revenues.... 4,907 6,530 9,007 13,431 13,781
+Gross profit--net sales...... 23,241 24,325 20,226 11,158 10,786
+Gross profit--contract
+revenues.................... 4,125 3,754 4,324 5,235 6,258
+------- -------- -------- -------- --------
+Total gross profit........... 27,366 28,079 24,550 16,393 17,044
+Selling, general and
+administrative expense...... 19,831 26,010 31,670 38,173 41,780
+Research and development
+expense..................... 7,734 9,271 11,191 16,888 18,812
+In process research and
+development................. -- 2,106 -- -- --
+Special charge............... -- 1,716 -- -- 6,285
+------- -------- -------- -------- --------
+Loss from operations......... (199) (10,924) (18,311) (38,668) (49,833)
+Non-operating income
+(expense)
+Royalty income............. -- -- -- 38,437 19,055
+Interest expense, net...... (183) (617) (1,807) (2,048) (1,762)
+------- -------- -------- -------- --------
+Loss before taxes............ (382) (11,541) (20,118) (2,279) (32,540)
+Income taxes (benefit)....... (181) (2,858) -- -- --
+------- -------- -------- -------- --------
+Loss from continuing
+operations.................. (201) (8,683) (20,118) (2,279) (32,540)
+Income from discontinued
+operations, net of income
+taxes....................... 3,931 2,089 -- -- --
+------- -------- -------- -------- --------
+Net income (loss)............ $ 3,730 $ (6,594) $(20,118) $ (2,279) $(32,540)
+======= ======== ======== ======== ========
+Diluted earnings (loss) per
+share:
+Continuing operations........ $ (0.03) $ (1.26) $ (2.57) $ (0.25) $ (3.26)
+Discontinued operations...... 0.62 0.31 -- -- --
+------- -------- -------- -------- --------
+Earnings (loss) per share.... $ 0.59 $ (0.95) $ (2.57) $ (0.25) $ (3.26)
+======= ======== ======== ======== ========
+Shares used in calculating
+diluted earnings (loss) per
+share....................... 6,299 6,912 7,820 9,089 9,977
+======= ======== ======== ======== ========
+Fiscal Year Ended March 31,
+-----------------------------------------------
+1997 1998 1999 2000 2001
+------- -------- -------- -------- --------
+(in thousands)
+Consolidated Balance Sheet
+Data:
+Working capital (deficit).... $21,903 $ 19,996 $ 15,216 $ 12,855 $ (8,845)
+Total assets................. 85,805 88,790 81,355 81,850 68,061
+Long-term debt (less current
+portion).................... 11,860 21,000 19,962 11,666 4,800
+Retained earnings (deficit).. 12,211 (3,795) (23,913) (26,192) (58,732)
+Total stockholders' equity... 51,828 38,580 36,323 36,110 20,378
+19
+ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
+RESULTS OF OPERATIONS.
+Results of Operations
+The following table sets forth certain income statement data as a percentage
+of total net sales and contract revenues for the periods indicated and should
+be read in conjunction with Management's Discussion and Analysis of Financial
+Condition and Results of Operations.
+As of March 31,
+---------------------
+1999 2000 2001
+----- ----- -----
+Net sales............................................... 84.0% 76.9% 74.0%
+Contract revenues....................................... 16.0 23.1 26.0
+----- ----- -----
+Total net sales and contract revenues................... 100.0% 100.0% 100.0%
+Gross profit--net sales................................. 28.9 18.0 18.9
+Gross profit--contract revenues......................... 32.4 28.1 31.2
+Selling, general and administrative expense............. 38.0 47.3 54.2
+Research and development expense........................ 13.4 20.9 24.4
+Special charge.......................................... -- -- 8.2
+Loss from operations.................................... (22.0) (47.9) (64.7)
+Non-operating income (expense):
+Royalty income........................................ -- 47.6 24.7
+Interest expense, net................................. (2.1) (2.5) (2.3)
+Income taxes (benefit).................................. -- -- --
+Net loss................................................ (24.1)% (2.8)% (42.2)%
+===== ===== =====
+General. We define our business segments as video products, telecom products
+and ITS. The video products segment includes our wholly-owned subsidiaries,
+Broadcast and Gyyr. The telecom products segment includes Zyfer, our wholly-
+owned subsidiary (formerly known as our Communications division) and
+Mariner Networks, our wholly-owned subsidiary. The ITS segment includes
+Odetics' 93% owned subsidiary, Iteris. In April 2001, Gyyr separated its
+operations into two divisions, Gyyr CCTV Products, which manufactures analog
+and digital storage solutions, and Gyyr Electronic Access Control, which
+manufactures enterprise security management systems. All references to our
+subsidiaries in this report include the prior business and results of
+operations of such subsidiaries as business units of Odetics prior to their
+incorporation.
+During the quarter ended December 31, 2000, we effected a restructuring to
+reduce our overall expenses and to further focus our business development on
+those areas that we believe provide the opportunity for the highest return on
+stockholder capital. This restructuring included a reduction of approximately
+25% of our total workforce and the discontinuation of certain product lines. As
+a result of these actions, we incurred charges in the amount of $9.4 million in
+the three months ended December 31, 2000. Of the total charges incurred,
+approximately $6.3 million was classified as a non-recurring special charge,
+representing severance payments and the write-down of certain assets.
+Net Sales and Contract Revenues. Net sales and contract revenues consist of
+(i) sales of products and services to commercial and municipal customers ("net
+sales") and (ii) revenue derived from contracts with state, county and
+municipal agencies for intelligent transportation systems projects ("contract
+revenues"). Contract revenues also include revenue from contracts with agencies
+of the United States Government and foreign entities for space-borne recorders
+used for geographical information systems. Total net sales and contract
+revenues decreased 4.5% to $77.1 million for the fiscal year ended March 31,
+2001 ("fiscal 2001") compared to $80.7 million for the fiscal year ended March
+31, 2000 ("fiscal 2000"), and decreased 3.2% for the fiscal year ended March
+31, 2000 compared to $83.4 million for the fiscal year ended March 31, 1999
+("fiscal 1999").
+20
+Net Sales. Net sales decreased 8.1% to $57.0 million in fiscal 2001
+compared to $62.0 million in fiscal 2000 as a result of declining sales in
+Broadcast, Mariner Networks and Gyyr, offset in part by increased sales in
+Iteris and Zyfer. Broadcast sales decreased 20.1% in fiscal 2001 compared
+to fiscal 2000 as a result of declining sales of its automated tape
+libraries. In the quarter ended December 31, 2000, Broadcast determined it
+would not pursue continued sales opportunities for its Roswell facility
+management system and shifted the focus of its business on sales of its
+AIRO Automation systems. Mariner Networks sales decreased 56.5% in fiscal
+2001 compared to fiscal 2000 as a result of the transition of its product
+offering entirely to its emerging Dexter family of multi-service access
+devices for the telecommunications market. Prior to this shift in product
+strategy, Mariner Networks had sold a variety of network access products
+that have been removed from its product line. Gyyr's sales decreased 10.8%
+in fiscal 2001 compared to fiscal 2000 due principally to the decline in
+sales of analog based time-lapse recorder product families. During the
+quarter ended June 30, 2001, Gyyr divested its Vortex Dome and Quarterback
+Controller product lines as part of a broader strategy to narrow its
+product offering to digital and analog recording and access control
+systems. Iteris' product sales increased 37% in fiscal 2001, primarily due
+to increased unit sales of its Vantage video detection products.
+Net sales decreased 11.4% to $62.0 million in fiscal 2000 compared to
+$70.0 million in fiscal 1999 as a result of declining sales in Broadcast,
+Mariner Networks and Gyyr. The decrease in Broadcast sales in fiscal 2000
+reflects delays in the delivery of our Roswell facility management system.
+The decline in Mariner Networks' sales reflects the loss in August 1999 of
+IBM as a significant OEM customer of its Frame product family. Gyyr's
+revenues declined 6.1% in fiscal 2000 compared to fiscal 1999 primarily as
+a result of declining sales of its analog based time-lapse recorder product
+families. Gyyr made substantial investments in expanding its product line
+to include a broad family of integrated security solutions, including the
+acquisition of a line of digital time-lapse recorders. This product line
+expansion was the result of our acquisition of the Security Products
+Division of Digital Systems Processing, Inc. in December 1999.
+Contributions of revenue in fiscal 2000 from the expanded product offerings
+were not significant enough to offset the declining revenues from analog-
+based time-lapse recorders.
+Contract Revenues. Contract revenues increased 7.4% to $20.0 million in
+fiscal 2001 compared to $18.7 million in fiscal 2000 and increased 40.0% in
+fiscal 2000 compared to $13.3 million in fiscal 1999. During fiscal 1999,
+we acquired Meyer Mohaddes Associates, Inc. and the assets of Viggen
+Corporation as part of a broader strategy to significantly grow our
+contract systems business in the ITS market. The growth in contract
+revenues in fiscal 2001 and fiscal 2000 reflects the successful execution
+of that strategy.
+Contract revenues derived from Iteris represented 83.5% of total
+contract revenues in fiscal 2000 compared to 64.9% of total contract
+revenues in fiscal 1999. The increase in Iteris' contract revenues in both
+fiscal 2001 and fiscal 2000 was offset by continued declines in contract
+revenues derived from the sale of space-borne recorders and related service
+and equipment to agencies of the United States Government. We have focused
+our recent contract procurement efforts on commercial markets and the
+markets for Iteris' products and services.
+Gross Profit. Total gross profit increased 4.0% to $17.0 million in fiscal
+2001, compared to $16.4 million in fiscal 2000, and decreased 33.2% in fiscal
+2000 compared to $24.6 million in fiscal 1999. Total gross profit as a percent
+of net sales and contract revenues increased to 22.1% in fiscal 2001, compared
+to 20.3% in fiscal 2000, and declined from 29.5% in fiscal 1999. Gross profit
+as a percent of net sales increased to 18.9% in fiscal 2001 compared to 18.0%
+in fiscal 2000. Gross profit in fiscal 2001 is net of charges totaling $3.1
+million, or 4.0% of net sales and contract revenues, related to the write-off
+of inventories associated with discontinued product lines in our Gyyr and
+Broadcast businesses. The charges were incurred in the third quarter of fiscal
+2001 and were part of an overall restructuring announced in January 2001.
+The increase in gross profit as a percent of net sales in fiscal 2001
+reflects increased gross profit on sales of Iteris Vantage products which
+comprised 17.5% of net sales in fiscal 2001 compared to 11.7% of net sales in
+fiscal 2000. In addition to improvements in Vantage gross profits, the gross
+profit performance in fiscal 2000 was
+21
+negatively impacted by pricing concessions to certain customers in our
+Broadcast business. During fiscal 2000, gross profit on net sales was also
+impaired due to our adjustments to inventory reserves and capitalized software
+related to certain discontinued products and product options in Mariner
+Networks, Broadcast and Gyyr.
+Gross profit as a percent of contract revenues increased to 31.2% in fiscal
+2001 compared to 28.0% in fiscal 2000. The increase in gross profit on contract
+revenues in fiscal 2001 reflects improved gross profit performance in both
+Iteris and Zyfer. We recognize contract revenues and related gross profit using
+percentage of completion contract accounting, and the related gross profit
+recognized in any given year is primarily affected by the underlying mix of
+contract activity.
+Gross profit as a percent of contract revenues decreased to 28.0% in fiscal
+2000 compared to 32.4% in fiscal 1999. Lower gross profit on contract revenues
+in fiscal 2000 reflect a mix of lower margin contract activity.
+Selling, General and Administrative Expense. Selling, general and
+administrative expense increased 9.4% to $41.8 million (or 54.2% of total net
+sales and contract revenues) compared to $38.2 million (or 47.2% of total net
+sales and contract revenues) in fiscal 2000, and increased 20.5% in fiscal 2000
+compared to $31.7 million (or 38.0% of total net sales and contract revenues)
+in fiscal 1999. During fiscal 2001, we increased expenditures for sales and
+marketing and general and administrative by approximately $4.2 million in
+Mariner Networks principally to fund its international sales and marketing
+organization to support the roll-out of its Dexter product offering. The
+increased expenditures were primarily in the area of salaries and related
+benefits, travel and living, trade shows, and advertising and promotion. The
+increase in sales and marketing expense in Mariner Networks was partially
+offset by decreased expenditures by Gyyr and Broadcast, which were part of our
+overall cost reduction plan. Iteris also experienced increased general and
+administrative expense in fiscal 2001 related to the build up of its
+administrative infrastructure to support its planned spin-off from Odetics,
+originally planned for the quarter ended June 30, 2000. As a result of the
+aborted public offering and spin-off, general and administrative expense in
+fiscal 2001 included a charge of approximately $360,000 related to the write-
+off of deferred public offering costs.
+During fiscal 2000, we increased expenditures for sales and marketing and
+general and administrative in Mariner Networks, Iteris and Broadcast.
+Concurrent with the completion of development of Mariner Networks' Dexter
+product and its progression to beta testing, we began building additional sales
+and marketing and administrative functions to support anticipated revenue
+growth. In preparation for the initial public offering of Iteris, we increased
+sales and marketing expense and general and administrative expense to enable
+Iteris to execute on its expansion plans and to function as an independent
+public company. In connection with this proposed public offering, we also
+adjusted the amortization periods for goodwill that arose upon the acquisition
+of the assets of the Transportation Systems business of Rockwell, and Meyer,
+Mohaddes Associates, Inc. The effect of the adjustment was an incremental
+charge to amortization expense of $887,000 during fiscal 2000. Iteris also
+experienced increased sales and marketing, and general and administrative
+expenses as a result of its acquisitions of Meyer Mohaddes Associates in
+October 1998, and of certain assets of Viggen Corporation in January 1999. In
+addition, the increase in selling, general and administrative expense in fiscal
+2000 reflects charges of approximately $500,000 for adjustment to the allowance
+for doubtful accounts in Broadcast.
+Research and Development Expense. Research and development expense increased
+11.4% to $18.8 million (or 24.4% of total net sales and contract revenues) in
+fiscal 2001 compared $16.9 million (or 20.9% of total net sales and contract
+revenues) in fiscal 2000, and increased 50.9% in fiscal 2000 compared to $11.2
+million (or 13.4% of total net sales and contract revenues) in fiscal 1999. For
+competitive reasons, we closely guard the confidentiality of specific
+development projects. The increase in research and development expense in
+fiscal 2001 reflects increased spending primarily by Mariner Networks and
+Iteris, partially offset by reductions ins spending by Gyyr and Broadcast. The
+increase in research and development expense by Mariner Networks reflects
+continued development of Dexter 3000, which was released for general
+availability to the market in June 2001. The increase in Iteris research and
+development expense largely represents expenditures to support its development
+initiatives for its Personalized Traveler Information Systems and, to a
+22
+lesser extent, continued development of its AutoVue product offering. As part
+of cost reduction initiatives completed in the quarter ended December 31, 2000,
+Iteris substantially reduced spending to support development of its
+Personalized Traveler Information Systems. Consequently, Iteris' research and
+development expense in the three months ended March 31, 2001 declined from the
+comparable three month period ended March 31, 2000. The reductions in research
+and development expense in Gyyr and Broadcast reflect the result of our overall
+expense reduction efforts.
+The increase in research and development expense in fiscal 2000 partly
+reflects the capitalization of certain development costs in fiscal 1999. During
+fiscal 1999, $2.8 million of development costs for Roswell and $2.1 million of
+development costs for Dexter were capitalized as qualified software development
+costs. The increase in research and development expense in fiscal 2000 also
+reflects increased expenditures by Iteris, Broadcast and Mariner Networks.
+Iteris increased its development activities 72.1% during fiscal 2000 to support
+its AutoVue product development. Broadcast continued to aggressively develop
+its Roswell facility management system and completed the development of its
+MicroStation product offering. All software development activities for
+Broadcast during fiscal 2000 were charged as research and development expense.
+Mariner Networks capitalized $300,000 of software development costs in fiscal
+2000, significantly expanded its product development team and increased
+research and development expenses 223.9% during fiscal 2000 compared to fiscal
+1999 to support the completion of its development schedule for Dexter in order
+to meet a targeted beta release of the product in the first quarter of fiscal
+2001. Gyyr reduced its expenses for product development 27.6% in fiscal 2000
+compared to fiscal 1999 in response to its efforts to reduce overall operating
+expenses and because it had completed several development initiatives as of the
+end of fiscal 1999. The change in Zyfer's product development expenses in
+fiscal 2000 compared to fiscal 1999 was not significant.
+Nonrecurring Charge. In December 2000, we recorded a nonrecurring charge of
+$6.3 million. Approximately $1.3 million of the charge reflects severance
+payments for staffing reductions, and the remainder represents non-cash charges
+for asset write-downs and reserves established in connection with the
+discontinuation of certain product lines.
+Royalty Income. In connection with the settlement of our action against
+StorageTek, we received proceeds, net of expenses and fees, of approximately
+$38.4 million in October 1999, and $17.8 million in June 2000 in full
+settlement of the amounts due us.
+Interest Expense, Net. Interest expense, net reflects the net of interest
+expense and interest income as follows:
+Year Ended March 31,
+--------------------
+1999 2000 2001
+------ ------ ------
+Interest expense........................................ $1,928 $2,313 $ 2012
+Interest income......................................... 121 265 250
+------ ------ ------
+Interest expense, net................................... $1,807 $2,048 $1,762
+====== ====== ======
+Interest expense decreased 13% in fiscal 2001 compared to fiscal 2000 and
+increased 20.0% in fiscal 2000 compared to fiscal 1999. Interest expense
+primarily reflects interest charges on our line of credit borrowings and
+mortgage interest. The fluctuations in interest expense in fiscal 2001 and
+fiscal 2000 represents changes in the average outstanding borrowings on our
+line of credit to fund negative operating cash flow. Interest income in fiscal
+2001 and fiscal 2000 is primarily related to interest earned on invested cash
+received from our settlement with StorageTek. Interest income in fiscal 1999
+was derived primarily from a note receivable due from ATL Products, Inc., our
+former subsidiary. ATL repaid in full the outstanding balance of its note
+receivable in July 1998.
+Income Taxes. We have not provided income tax benefit for the losses
+incurred in fiscal 2001, 2000 and 1999 due to the uncertainty as to the
+ultimate realization of the benefit.
+23
+Liquidity and Capital Resources
+During fiscal 2001 and 2000, we reported operating losses of $49.8 million
+and $38.7 million, respectively, and we had a working capital deficiency of
+$8.8 million at March 31, 2001. We financed our operations in fiscal 2001 and
+2000 largely through cash received from the settlement of certain litigation
+with StorageTek, debt and equity financings and, to a lesser extent, through
+the sale of assets of certain of our subsidiaries.
+In October 1999, we settled litigation with StorageTek in exchange for
+license fees payable to us in the aggregate amount of $100.0 million, $80.0
+million of which was paid on the settlement date (resulting in net cash to us
+of $38.4 million after payment of the related expenses). In June 2000, we
+amended the settlement agreement with StorageTek to provide for the
+acceleration of the payment of the $20.0 million still owed to us. Under the
+terms of the amendment, StorageTek paid us $17.8 million in cash during fiscal
+2001 to complete the settlement.
+During fiscal 2001, we used $20.1 million of cash to fund operations, which
+reflects our net loss of $32.5 million, offset by non-cash charges of $5.0
+million for depreciation and amortization, $4.0 million for the write off of
+capitalized software and goodwill, and a $4.6 million reduction in net
+operating assets and liabilities. During fiscal 2001, we also sold certain
+assets of Zyfer and of our solid state recording product line for $1.9 million
+in cash. In connection with these sales, we recorded a non-operating gain of
+$1.2 million.
+In fiscal 2000, we sold an option to purchase our principal facilities in
+Anaheim California to Manchester Capital LLC for an aggregate purchase price of
+$5.0 million. We used $5.6 million in cash in fiscal 2001 to repurchase this
+option, which included accrued interest.
+At March 31, 2001, we had $13.5 million outstanding on a $17.0 million line
+of credit with Transamerica Business Credit. While this line of credit expired
+on December 31, 2000, we received an extension until July 31, 2001. In
+addition, due to the breach of certain financial and other covenants under this
+line of credit, we entered into a forbearance agreement in May 2001 with
+Transamerica that expires July 31, 2001. Under the terms of this forbearance
+agreement and the extension, we are prohibited from making further borrowings
+under the line of credit.
+In May 2001, we received $16.0 million pursuant to a promissory note secured
+by a first trust deed on our principal facilities in Anaheim, California. This
+promissory note is due in May 2002 and bears annual interest at the rate of
+10%. In connection with this loan, we issued warrants to this lender to
+purchase 426,667 shares of our Class A common stock at an exercise price of $4
+per share. If we prepay this note prior to six months following its issuance,
+the lender, at its option, may convert up to $1.6 million of the principal
+amount on this note into our Class A common stock at a conversion price of $4
+per share.
+Of the $16.0 million proceeds received from the promissory note financing,
+we used approximately $6 million to retire the pre-existing first trust deed on
+our Anaheim real property and $5.9 million to reduce the borrowings due
+Transamerica under the line of credit to $7.6 million in May 2001 in accordance
+with the terms of the forbearance agreement. We used the balance of the
+proceeds from this financing, after payment of expenses, for general working
+capital purposes.
+In January 2001, we announced that in response to tightening credit and
+capital markets we were taking a number of actions to reduce our operating
+expenses, improve our gross profit and operating profit performance, and narrow
+our negative operating cash flow and operating losses. Concurrent with those
+actions, we incurred charges in the three months ended December 31, 2000
+totaling $9.4 million. Approximately $1.3 million of these charges incurred
+were cash charges related to severance payments for staffing reductions and the
+balance were non-cash charges related to asset write-downs and reserves
+established in connection with the discontinuation of certain products.
+We expect that our operations will continue to use net cash for the
+foreseeable future. During fiscal 2002, we expect to have an ongoing need to
+raise cash by securing additional debt or equity financing, or by divesting
+certain assets to fund our operations until they return to profitability and
+positive operating cash
+24
+flow. We are currently considering the sale and leaseback of our principal
+operating facilities in Anaheim, California and are in negotiations with a
+financial institution to provide a new line of credit. We cannot be certain
+that our plan to sell and leaseback of our facilities will be successful, that
+we will be able to secure a new line of credit on terms acceptable to us, or at
+all, or that our existing lender will continue to extend our existing borrowing
+relationship. Our future cash requirements will be highly dependent on our
+ability to control expenses as well as the successful execution of the revenue
+plans by each of our businesses. As a result, any projections of future cash
+requirements and cash flows are subject to substantial uncertainty.
+These conditions, together with our recurring operating losses, raise
+substantial doubt about our ability to continue as a going concern. Our
+consolidated financial statements do not include any adjustments to reflect the
+possible future effects on the recoverability and classification of assets or
+liabilities that may result from the outcome of this uncertainty.
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.
+We are exposed to interest rate risk primarily from our long-term debt
+arrangements. Under our current policies, we do not use interest rate
+derivative instruments to manage our exposure to interest rate changes.
+The following table provides information about our debt obligations that are
+sensitive to changes in interest rates.
+Expected maturity date March 31,
+------------------------------------------------
+Fair
+2002 2003 2004 2005 Total value
+------ ------ ------ ------ ------- -------
+(dollars in thousands)
+Fixed rate debt.............. $6,990 $1,804 $1,653 $1,343 $11,790 $11,790
+Average interest rate........ 8.87% 9.18% 9.36% 9.36% 9.02%
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
+The financial statements and supplementary data required by Regulation S-X
+are included in thisForm 10-K commencing on page F-1.
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
+FINANCIAL DISCLOSURE.
+Not applicable.
+25
+PART III
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
+(a) Identification of Directors. The information under the heading "Election
+of Directors," appearing in our proxy statement, is incorporated herein by
+reference.
+(b) Identification of Executive Officers. The information under the heading
+"Executive Compensation and Other Information," appearing in our proxy
+statement, is incorporated herein by reference.
+(c) Compliance with Section 16(a) of the Exchange Act. The information under
+the heading "Executive Compensation and Other Information," appearing in our
+proxy statement, is incorporated herein by reference.
+ITEM 11. EXECUTIVE COMPENSATION.
+The information under the heading "Executive Compensation," appearing in our
+proxy statement, is incorporated herein by reference.
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
+The information under the heading "Principal Stockholders and Common Stock
+Ownership of Certain Beneficial Owners and Management," appearing in our proxy
+statement, is incorporated herein by reference.
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
+The information under the heading "Certain Transactions," appearing in our
+proxy statement, is incorporated herein by reference.
+26
+PART IV
+ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
+(a) Documents filed as part of this report:
+1. Financial Statements. The following financial statements of Odetics are
+included in a separate section of this Annual Report on Form 10-K commencing on
+the pages referenced below:
+Page
+----
+Report of Independent Auditors........................................ F-2
+Consolidated Balance Sheets as of March 31, 2000 and 2001............. F-3
+Consolidated Statements of Operations for the years ended March 31,
+1999, 2000 and 2001.................................................. F-4
+Consolidated Statements of Stockholders' Equity for the years ended
+March 31, 1999, 2000 and 2001........................................ F-5
+Consolidated Statements of Cash Flows for the years ended March 31,
+1999, 2000 and 2001.................................................. F-6
+Notes to Consolidated Financial Statements............................ F-7
+2. Financial Statement Schedules.
+Schedule II -- Valuation and Qualifying Accounts......................... S-1
+All other schedules have been omitted because they are not required or the
+required information is included in our consolidated financial statements and
+notes thereto.
+3. Exhibits.
+3.1 Certificate of Incorporation of Odetics, as amended (incorporated by
+reference to Exhibit 19.2 to Odetics' Quarterly Report on Form 10-Q for
+the quarter ended September 30, 1987).
+3.2 Bylaws of Odetics, as amended (incorporated by reference to Exhibit 4.2
+to Odetics' Registration Statement on Form S-1 (Reg. No. 033-67932) as
+filed with the SEC on July 6, 1993).
+4.1 Specimen of Class A Common Stock and Class B Common Stock certificates
+(incorporated by reference to Exhibit 4.3 to Amendment No. 1 to Odetics'
+Registration Statement on Form S-1
+(Reg. No. 033-67932) as filed with the SEC on September 30, 1993).
+4.2 Form of rights certificate for Odetics' preferred stock purchase rights
+(incorporated by reference to Exhibit A of Exhibit 4 to Odetics' Current
+Report on Form 8-K as filed with the SEC on May 1, 1998).
+10.1 Profit Sharing Plan and Trust (incorporated by reference to Exhibit 10.3
+to Odetics' Amendment No. 2 to the Registration Statement on Form S-8
+(Reg. No. 002-98656) as filed with the SEC on May 5, 1988).
+10.2 Form of Executive Deferral Plan between Odetics and certain employees of
+Odetics (incorporated by reference to Exhibit 10.4 to Odetics' Annual
+Report on Form 10-K for the year ended March 31, 1988).
+10.3 Loan and Security Agreement dated December 28, 1998 among Transamerica
+Business Credit Corporation, Odetics and the subsidiaries of Odetics, and
+Schedule to Loan Agreement (incorporated by reference to the same exhibit
+number in Odetics' Annual Report on Form 10-K for the year ended March
+31, 1999).
+10.4 Amendment to Loan Agreement dated December 28, 1998 among Transamerica
+Business Credit Corporation, Odetics and the subsidiaries of Odetics, and
+related Schedule to Loan Agreement dated December 28, 1998 (incorporated
+by reference to the same exhibit number in Odetics' Annual Report on Form
+10-K for the year ended March 31, 1999).
+27
+10.5 Revolving Credit Note dated December 28, 1998 payable to Transamerica
+Business Credit Corporation in the original principal amount of
+$17,000,000 (incorporated by reference to the same exhibit number in
+Odetics' Annual Report on Form 10-K for the year ended March 31, 1999).
+10.6 Letter of Credit Agreement dated December 28, 1998 among Transamerica
+Business Credit Corporation, Odetics and the subsidiaries of Odetics
+(incorporated by reference to the same exhibit number in Odetics' Annual
+Report on Form 10-K for the year ended March 31, 1999).
+10.7 Security Agreement in Copyrighted Works dated December 28, 1998 between
+Transamerica Business Credit Corporation and Odetics (incorporated by
+reference to the same exhibit number in Odetics' Annual Report on Form
+10-K for the year ended March 31, 1999).
+10.8 Patent and Trademark Security Agreement dated December 28, 1998 between
+Transamerica Business Credit Corporation and Odetics (incorporated by
+reference to the same exhibit number in Odetics' Annual Report on Form
+10-K for the year ended March 31, 1999).
+10.9 Cross-Corporate Continuing Guaranty dated December 28, 1998 among
+Transamerica Business Credit Corporation, Odetics and the subsidiaries
+of Odetics (incorporated by reference to the same exhibit number in
+Odetics' Annual Report on Form 10-K for the year ended March 31, 1999).
+10.10 Amendments to Loan Agreement dated December 22, 2000, February 28, 2001
+and May 29, 2001 among Transamerica Business Credit Corporation and
+Odetics and its subsidiaries.
+10.11 Forbearance Agreement dated May 28, 2001 among Transamerica Business
+Credit Corporation and Odetics and its subsidiaries.
+10.12 Form of Indemnity Agreement entered into by Odetics and certain of its
+officers and directors (incorporated by reference to Exhibit 19.4 to
+Odetics' Quarterly Report on Form 10-Q for the quarter ended September
+30, 1988).
+10.13 Schedule of officers and directors covered by Indemnity Agreement
+(incorporated by reference to Exhibit 10.9.2 to Amendment No. 1 to
+Odetics' Registration Statement on Form S-1 (Reg. No. 033-67932) as
+filed with the SEC on July 6, 1993).
+10.14 Amendment Nos. 3 and 4 to the Profit Sharing Plan and Trust
+(incorporated by reference to Exhibits 4.3.1 and 4.3.2, respectively, to
+Amendment No. 3 to Odetics' Registration Statement on Form S-3 (Reg. No.
+002-86220) as filed with the SEC on June 13, 1990).
+10.15 1997 Stock Incentive Plan of Odetics (incorporated by reference to
+Exhibit 99.1 to Odetics' Registration Statement on Form S-8 (File No.
+333-30396) as filed with the SEC on February 14, 2000).
+10.16 Form of Notice of Grant of Stock Option (incorporated by reference to
+Exhibit 99.2 to Odetics' Registration Statement on Form S-8 (File No.
+333-30396) as filed with the SEC on February 14, 2000)
+10.17 Form of Stock Option Agreement (incorporated by reference to Exhibit
+99.3 to Odetics' Registration Statement on Form S-8 (File No. 333-30396)
+as filed with the SEC on February 14, 2000).
+10.18 Form of Addendum to Stock Option Agreement--Involuntary Termination
+Following Corporate Transaction or Change in Control (incorporated by
+reference to Exhibit 99.4 to Odetics' Registration Statement on Form S-8
+(File No. 333-30396) as filed with the SEC on February 14, 2000).
+10.19 Form of Addendum to Stock Option Agreement--Limited Stock Appreciation
+Rights (incorporated by reference to Exhibit 99.5 to Odetics'
+Registration Statement on Form S-8 (File No. 333-30396) as filed with
+the SEC on February 14, 2000).
+10.20 Form of Stock Issuance Agreement (incorporated by reference to Exhibit
+99.6 to Odetics' Registration Statement on Form S-8 (File No. 333-30396)
+as filed with the SEC on February 14, 2000)
+10.21 Form of Addendum to Stock Issuance Agreement--Involuntary Termination
+Following Corporate Transaction/Change in Control (incorporated by
+reference to Exhibit 99.7 to Odetics' Registration Statement on Form S-8
+(File No. 333-30396) as filed with the SEC on February 14, 2000).
+10.22 Form of Notice of Grant of Automatic Stock Option--Initial Grant filed
+as Exhibit 99.8 filed as Exhibit (incorporated by reference to Exhibit
+99.8 to Odetics' Registration Statement on Form S-8 (File No. 333-30396)
+as filed with the SEC on February 14, 2000).
+28
+10.23 Form of Notice of Grant of Automatic Stock Option--Annual Grant
+(incorporated by reference to Exhibit 99.9 to Odetics' Registration
+Statement on Form S-8 (File No. 333-30396) as filed with the SEC on
+February 14, 2000).
+10.24 Form of Automatic Stock Option Agreement filed as Exhibit 99.10 to the
+(incorporated by reference to Exhibit 99.10 to Odetics' Registration
+Statement on Form S-8 (File No. 333-30396) as filed with the SEC on
+February 19, 2000).
+10.25 Rights Agreement dated April 24, 1998 between Odetics and BankBoston,
+N.A., which includes the form of Certificate of Designation for the
+junior participating preferred stock as Exhibit A, the form of rights
+certificate as Exhibit B and the summary of rights to purchase Series A
+preferred shares as Exhibit C (incorporated by reference to Exhibit 4 to
+Odetics' Current Report on Form 8-K as filed with the SEC on May 1,
+1998).
+10.26 1994 Long-Term Equity Plan of Odetics (incorporated by reference to
+Exhibit 4.3 to Odetics' Registration Statement on Form S-8 (File No.
+333-05735) as filed with the SEC on June 11, 1996).
+10.27 Subordinated Convertible Note Purchase Agreement dated January 25, 2000
+between Iteris, Inc. and DaimlerChrysler GmbH (incorporated by reference
+to Exhibit 10.31 to Odetics' Annual Report on Form 10-K as filed with
+the SEC on June 29, 2000).
+10.28 Subordinated Convertible Note dated January 25, 2000 between Iteris,
+Inc. and DaimlerChrysler GmbH (incorporated by reference to Exhibit
+10.32 to Odetics' Annual Report on Form 10-K as filed with the SEC on
+June 29, 2000).
+10.29 Securities Purchase Agreement dated May 29, 2001, by and between Odetics
+and Castle Creek Technology Partners LLC. Included from the Agreement
+are Exhibit A (form of Senior Convertible Promissory Note), Exhibit B-1
+(form of Stock Purchase Warrant), Exhibit B-2 (form of Stock Purchase
+Warrant), Exhibit B-3 (form of Stock Purchase Warrant), and Exhibit D
+(form of Deed of Trust) (incorporated by reference to Exhibit 99.1 to
+Odetics' Current Report on Form 8-K as filed with the SEC on June 1,
+2001).
+10.30 Registration Rights Agreement dated May 29, 2001, by and between Odetics
+and Castle Creek Technology Partners LLC (incorporated by reference to
+Exhibit 99.2 to Odetics' Current Report on Form 8-K as filed with the
+SEC on June 1, 2001).
+10.31 Amendment to Rights Agreement, dated May 21, 2001, by and between
+Odetics and Fleet National Bank (a.k.a. Bank Boston, N.A. (incorporated
+by reference to Exhibit 99.4 to Odetics' Current Report on Form 8-K as
+filed with the SEC on June 1, 2001).
+21 Subsidiaries of Odetics (incorporated by reference to Exhibit 21 to
+Odetics' Annual Report on Form 10-K as filed with the SEC on June 29,
+2000).
+23.1 Consent of Independent Auditors.
+(b) Reports on Form 8-K
+On August 16, 2000, we filed a Current Report on Form 8-K to announce that
+Iteris, Inc., a subsidiary of Odetics, Inc., reached an agreement with Ford
+Motor Company to become the exclusive supplier of the optical lane departure
+warning systems to be installed on future Ford, Lincoln and Mercury badged
+vehicles produced and sold in the United States. Under terms of the agreement,
+Ford will receive warrants to purchase up to approximately 9.9% of Iteris
+common stock if Ford meets predetermined Auto Vue purchase volumes over the six
+year term of the agreement. The warrants will not be fully exercisable until
+Ford purchases a number of units that results in sales of approximately $90
+million dollars over the life of the agreement. However, Ford has no obligation
+to purchase any Auto Vue products under the agreement. Ford will not play a
+role in the management of Iteris.
+29
+SIGNATURES
+Pursuant to the requirements of Section 13 or 15(d) of the Securities
+Exchange Act of 1934, the Registrant has duly caused this Report to be signed
+on its behalf by the undersigned, thereunto duly authorized, in the City of
+Anaheim, State of California, on July 13, 2001.
+ODETICS, INC.
+By: _________________________________
+Joel Slutzky
+Chief Executive Officer, President
+and Chairman of the Board
+POWER OF ATTORNEY
+We, the undersigned officers and directors of Odetics, Inc., do hereby
+constitute and appoint Joel Slutzky and Gregory A. Miner, and each of them, our
+true and lawful attorneys-in-fact and agents, each with full power of
+substitution and resubstitution, for him and in his name, place and stead, in
+any and all capacities, to sign any and all amendments to this report, and to
+file the same, with exhibits thereto, and other documents in connection
+therewith, with the Securities and Exchange Commission, granting unto said
+attorneys-in-fact and agents, and each of them, full power and authority to do
+and perform each and every act and thing requisite or necessary to be done in
+and about the premises, as fully to all intents and purposes as he might or
+could do in person, hereby, ratifying and confirming all that each of said
+attorneys-in-fact and agents, or his substitute or substitutes, may lawfully do
+or cause to be done by virtue hereof.
+Pursuant to the requirements of the Securities Exchange Act of 1934, this
+report has been signed below by the following persons in the capacities and on
+the dates indicated:
+Signature Title Date
+--------- ----- ----
+/s/ Joel Slutzky Chief Executive Officer, July 13, 2001
+____________________________________ President and Chairman of
+Joel Slutzky the Board (principal
+executive officer)
+/s/ Crandall Gudmundson Director July 13, 2001
+____________________________________
+Crandall Gudmundson
+/s/ Jerry Muench Director July 13, 2001
+____________________________________
+Jerry Muench
+/s/ Kevin C. Daly Director July 13, 2001
+____________________________________
+Kevin C. Daly
+/s/ Gary Smith Vice President and July 13, 2001
+____________________________________ Controller (principal
+Gary Smith accounting officer)
+/s/ Thomas L. Thomas Director July 13, 2001
+____________________________________
+Thomas L. Thomas
+30
+Signature Title Date
+--------- ----- ----
+/s/ John Seazholtz Director July 13, 2001
+____________________________________
+John Seazholtz
+/s/ Paul E. Wright Director July 13, 2001
+____________________________________
+Paul E. Wright
+/s/ Gregory A. Miner Vice President, Director and July 13, 2001
+____________________________________ Chief Operating Officer and
+Gregory A. Miner Chief Financial Officer
+(principal financial
+officer)
+31
+ODETICS, INC.
+INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
+Page
+----
+Report of Independent Auditors........................................... F-2
+Consolidated Balance Sheets as of March 31, 2000 and 2001................ F-3
+Consolidated Statements of Operations for the years ended March 31, 1999,
+2000 and 2001........................................................... F-5
+Consolidated Statements of Stockholders' Equity for the years ended March
+31, 1999, 2000 and 2001................................................. F-6
+Consolidated Statements of Cash Flows for the years ended March 31, 1999,
+2000 and 2001........................................................... F-7
+Notes to Consolidated Financial Statements............................... F-8
+F-1
+REPORT OF INDEPENDENT AUDITORS
+Stockholders and Board of Directors
+Odetics, Inc.
+We have audited the accompanying consolidated balance sheets of Odetics,
+Inc. as of March 31, 2000 and 2001, and the related consolidated statements of
+operations, stockholders' equity, and cash flows for each of the three years in
+the period ended March 31, 2001. Our audits also included the financial
+statement schedule listed in Item 14(a). These financial statements and
+schedule are the responsibility of the Company's management. Our responsibility
+is to express an opinion on these financial statements and schedule based on
+our audits.
+We conducted our audits in accordance with auditing standards generally
+accepted in the United States. Those standards require that we plan and perform
+the audit to obtain reasonable assurance about whether the financial statements
+are free of material misstatement. An audit includes examining, on a test
+basis, evidence supporting the amounts and disclosures in the financial
+statements. An audit also includes assessing the accounting principles used and
+significant estimates made by management, as well as evaluating the overall
+financial statement presentation. We believe that our audits provide a
+reasonable basis for our opinion.
+In our opinion, the consolidated financial statements referred to above
+present fairly, in all material respects, the consolidated financial position
+of Odetics, Inc. at March 31, 2000 and 2001, and the consolidated results of
+its operations and its cash flows for each of the three years in the period
+ended March 31, 2001, in conformity with accounting principles generally
+accepted in the United States. Also, in our opinion, the related financial
+statement schedule, when considered in relation to the basic financial
+statements taken as a whole, presents fairly in all material respects the
+information set forth therein.
+The accompanying consolidated financial statements have been prepared
+assuming the Company will continue as a going concern. As discussed in Note 1
+to the consolidated financial statements, the Company's recurring losses from
+operations and working capital deficit raise substantial doubt about its
+ability to continue as a going concern. Management's plans as to these matters
+are also described in Note 1. The consolidated financial statements do not
+include any adjustments that might result from the outcome of this uncertainty.
+/s/ Ernst & Young LLP
+Orange County, California
+May 15, 2001, except for Notes 1 and 16,
+as to which the date is May 29, 2001
+F-2
+ODETICS, INC.
+CONSOLIDATED BALANCE SHEETS
+(In thousands, except share and per share amounts)
+March 31
+------------------
+2000 2001
+-------- --------
+ASSETS
+------
+Current assets:
+Cash and cash equivalents................................ $ 4,880 $ 2,218
+Trade accounts receivable, net of allowance for doubtful
+accounts of $2,068 in 2000 and $1,644 in 2001........... 13,576 14,380
+Costs and estimated earnings in excess of billings on
+uncompleted contracts................................... 3,283 3,296
+Inventories:
+Finished goods........................................... 1,203 1,644
+Work in process.......................................... 859 51
+Materials and supplies................................... 16,150 11,371
+Prepaid expenses and other............................... 1,978 1,078
+-------- --------
+Total current assets................................... 41,929 34,038
+Property, plant and equipment:
+Land..................................................... 2,060 2,060
+Buildings and improvements............................... 18,868 18,982
+Equipment................................................ 30,652 32,667
+Furniture and fixtures................................... 2,676 2,692
+Allowances for depreciation.............................. (33,520) (35,266)
+-------- --------
+20,736 21,135
+Capitalized software costs, net............................ 6,482 2,090
+Goodwill, net of accumulated amortization of $2,723 in 2000
+and $1,924 in 2001........................................ 12,004 10,622
+Other assets............................................... 699 176
+-------- --------
+Total assets............................................... $ 81,850 $ 68,061
+======== ========
+F-3
+ODETICS, INC.
+CONSOLIDATED BALANCE SHEETS--(continued)
+(In thousands, except share and per share amounts)
+March 31
+------------------
+2000 2001
+-------- --------
+LIABILITIES AND STOCKHOLDERS' EQUITY
+------------------------------------
+Current liabilities:
+Trade accounts payable................................... $ 10,702 $ 10,644
+Accrued payroll and related.............................. 4,892 4,559
+Accrued expenses......................................... 2,313 2,354
+Contract reserve......................................... 3,056 2,290
+Billings in excess of costs and estimated earnings on
+uncompleted contracts................................... 1,303 2,575
+Revolving line of credit................................. 3,706 13,471
+Current portion of long-term debt........................ 3,102 6,990
+-------- --------
+Total current liabilities.................................. 29,074 42,883
+Long-term debt, less current portion....................... 11,666 4,800
+Other liabilities.......................................... 5,000 --
+Commitments (Note 12)
+Stockholders' equity:
+Preferred stock:
+Authorized shares--2,000,000
+Issued and outstanding--none........................... -- --
+Common stock, $.10 par value:
+Authorized shares--10,000,000 of Class A and 2,600,000
+of Class B
+Issued and outstanding shares--8,183,470 of Class A and
+1,051,541 of Class B at March 31, 2000; 9,468,620 of
+Class A and 1,035,841 of Class B at March 31, 2001.... 923 1,050
+Paid-in capital.......................................... 61,200 78,548
+Treasury stock, 4,564 and 93 shares in 2000 and 2001,
+respectively............................................ (22) (1)
+Notes receivable from employees ......................... (61) (51)
+Accumulated other comprehensive income (loss)............ 262 (436)
+Accumulated deficit...................................... (26,192) (58,732)
+-------- --------
+Total stockholders' equity................................. 36,110 20,378
+-------- --------
+Total liabilities and stockholders' equity................. $ 81,850 $ 68,061
+======== ========
+See accompanying notes.
+F -4
+ODETICS, INC.
+CONSOLIDATED STATEMENTS OF OPERATIONS
+(In thousands, except per share information)
+Year ended March 31
+----------------------------
+1999 2000 2001
+-------- -------- --------
+Net sales and contract revenues:
+Net sales..................................... $ 70,042 $ 62,041 $ 57,030
+Contract revenues............................. 13,331 18,666 20,039
+-------- -------- --------
+83,373 80,707 77,069
+Costs and expenses:
+Cost of sales................................. 49,816 50,883 46,244
+Cost of contract revenues..................... 9,007 13,431 13,781
+Selling, general and administrative expense... 31,670 38,173 41,780
+Research and development expense.............. 11,191 16,888 18,812
+Special charge................................ -- -- 6,285
+-------- -------- --------
+101,684 119,375 126,902
+-------- -------- --------
+Loss from operations............................ (18,311) (38,668) (49,833)
+Non-operating income (expense)
+Royalty income................................ -- 38,437 17,825
+Gain on sale of product lines................. -- -- 1,230
+Interest expense, net......................... (1,807) (2,048) (1,762)
+-------- -------- --------
+Net loss........................................ $(20,118) $ (2,279) $(32,540)
+======== ======== ========
+Basic and diluted loss per share................ $ (2.57) $ (0.25) $ (3.26)
+======== ======== ========
+Shares used in computing basic and diluted loss
+per share...................................... 7,820 9,089 9,977
+======== ======== ========
+See accompanying notes.
+F-5
+ODETICS, INC.
+CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
+(In thousands)
+Common stock
+---------------------
+Shares
+outstanding
+-------------
+Class Class Notes Accumulated
+A B receivable other Compre-
+common common Paid-in Treasury from comprehensive Accumulated hensive
+stock stock Amount capital stock employees income (loss) deficit Total income
+------ ------ ------ ------- -------- ---------- ------------- ----------- -------- --------
+Balance at March 31,
+1998................... 6,203 1,062 $ 726 $45,240 $(239) $(3,377) $ 25 $ (3,795) $ 38,580
+Issuances of common
+stock ............... 1,736 -- 175 14,339 -- -- -- -- 14,514
+Conversion of Class B
+common stock......... 2 (2) -- -- -- -- -- -- --
+Purchase of treasury
+stock................ -- -- -- -- (1) -- -- -- (1)
+Payments on notes
+receivable........... -- -- -- -- -- 3,281 -- -- 3,281
+Foreign currency
+translation
+adjustments.......... -- -- -- -- -- -- 67 -- 67 $ 67
+Net loss.............. -- -- -- -- -- -- -- (20,118) (20,118) (20,118)
+----- ----- ------ ------- ----- ------- ----- -------- -------- --------
+Balance at March 31,
+1999................... 7,941 1,060 901 59,579 (240) (96) 92 (23,913) 36,323 $(20,051)
+========
+Issuances of common
+stock ............... 234 -- 22 1,621 218 -- -- -- 1,861
+Conversion of Class B
+common stock......... 8 (8) -- -- -- -- -- -- --
+Payments on notes
+receivable........... -- -- -- -- -- 35 -- -- 35
+Foreign currency
+translation
+adjustments.......... -- -- -- -- -- -- 170 -- 170 $ 170
+Net loss.............. -- -- -- -- -- -- -- (2,279) (2,279) (2,279)
+----- ----- ------ ------- ----- ------- ----- -------- -------- --------
+Balance at March 31,
+2000................... 8,183 1,052 923 61,200 (22) (61) 262 (26,192) 36,110 $ (2,109)
+========
+Issuances of common
+stock ............... 1,270 -- 127 17,348 21 -- -- -- 17,496
+Conversion of Class B
+common stock......... 16 (16) -- -- -- -- -- -- --
+Payments on notes
+receivable........... -- -- -- -- -- 10 -- -- 10
+Foreign currency
+translation
+adjustments.......... -- -- -- -- -- -- (698) -- (698) $ (698)
+Net loss.............. -- -- -- -- -- -- -- (32,540) (32,540) (32,540)
+----- ----- ------ ------- ----- ------- ----- -------- -------- --------
+Balance at March 31,
+2001................... 9,469 1,036 $1,050 $78,548 $ (1) $ (51) $(436) $(58,732) $ 20,378 $(33,238)
+===== ===== ====== ======= ===== ======= ===== ======== ======== ========
+See accompanying notes.
+F-6
+ODETICS, INC.
+CONSOLIDATED STATEMENTS OF CASH FLOWS
+(In thousands)
+Year ended March 31
+----------------------------
+1999 2000 2001
+-------- -------- --------
+Operating activities
+Net loss......................................... $(20,118) $ (2,279) $(32,540)
+Adjustments to reconcile net loss to net cash
+used in operating activities:
+Depreciation and amortization.................. 5,205 7,185 4,967
+Write-off of capitalized software.............. -- -- 4,014
+Gain on sale of product lines.................. -- -- (1,230)
+Provision for losses on accounts receivable.... 332 745 78
+Provision for deferred income taxes............ 915 -- --
+Changes in operating assets and liabilities
+(Note 14)..................................... 1,560 1,179 4,621
+-------- -------- --------
+Net cash provided by (used in) operating
+activities.................................. (12,106) 6,830 (20,090)
+Investing activities
+Purchases of property, plant and equipment, net.. (2,747) (2,169) (2,502)
+Repurchase of real estate option................. -- -- (5,000)
+Proceeds from sale of product lines.............. -- -- 1,877
+Proceeds from option to sell real estate......... -- 5,000 --
+Software development costs....................... (4,944) (330) --
+Purchase of net assets of acquired business...... -- (1,500) (42)
+Net cash received from ATL....................... 10,019 -- --
+Other............................................ -- 213 (688)
+-------- -------- --------
+Net cash provided by (used in) investing
+activities.................................. 2,328 1,214 (6,355)
+Financing activities
+Proceeds from line of credit and long-term
+borrowings...................................... 44,527 23,966 26,644
+Principal payments on line of credit and long-
+term debt....................................... (45,089) (29,528) (19,857)
+Proceeds from issuance of common stock........... 9,996 1,611 16,996
+-------- -------- --------
+Net cash provided by (used in) financing
+activities...................................... 9,434 (3,951) 23,783
+-------- -------- --------
+Increase (decrease) in cash...................... (344) 4,093 (2,662)
+Cash and cash equivalents at beginning of year... 1,131 787 4,880
+-------- -------- --------
+Cash and cash equivalents at end of year......... $ 787 $ 4,880 $ 2,218
+======== ======== ========
+See accompanying notes.
+F-7
+ODETICS, INC
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+March 31, 2001
+1. Formation and Operations
+Odetics, Inc. (the Company) serves as a developer of technology oriented
+companies, each with its own marketplace, customers and products, including the
+Company's wholly-owned subsidiaries Gyyr, Inc., Broadcast, Inc., Mariner
+Networks, Inc., Zyfer, Inc., Odetics Europe Limited, Odetics GYYR Limited,
+Odetics Mariner Limited, Odetics Asia Pacific Pte. Ltd., and its 93% owned
+subsidiary, Iteris, Inc.
+In January 2001, the Company announced that in response to tightening credit
+and capital markets it was taking a number of actions to reduce its operating
+expenses, improve its gross profit and operating profit performance, and narrow
+its negative operating cash flow and operating losses. Concurrent with those
+actions, the Company incurred charges in the three months ended December 31,
+2000 totaling $9.4 million (Note 4). Including these charges, during fiscal
+2001 and 2000, the Company experienced operating losses of $49.8 million and
+$38.7, respectively, and at March 31, 2001 had a working capital deficit of
+$8.8 million.
+Contributing to the working capital deficit at March 31, 2001, is $13.5
+million of borrowings from Transamerica Business Credit under a $17.0 million
+line of credit. This line of credit expired on December 31, 2000, however, the
+Company received an extension until July 31, 2001. Due to the breach of certain
+financial and other covenants under this line of credit, the Company entered
+into a forbearance agreement with Transamerica in May 2001. Under the terms of
+this forbearance agreement and the extension, the Company is prohibited from
+making any further borrowings under the line of credit.
+The Company financed its operations in fiscal 2000 and 2001 largely through
+cash received from the settlement of certain litigation with StorageTek (Note
+15), debt and equity financings and, to a lesser extent, through the sale of
+assets of certain of its subsidiaries.
+In May 2001, the Company received $16.0 million pursuant to a promissory
+note secured by a first trust deed on its principal facilities in Anaheim,
+California. This promissory note is due in May 2002 and bears annual interest
+at the rate of 10%. Of the $16.0 million of proceeds received from the
+promissory note financing, the Company used approximately $6.0 million to
+retire the pre-existing first trust deed on its Anaheim real property and $5.9
+million to reduce the borrowings due Transamerica under the line of credit to
+$7.6 million in accordance with the terms of the forbearance agreement. The
+balance of the proceeds from this financing, after payment of expenses, is
+available to the Company for general working capital purposes.
+The Company expects that its operations will continue to use net cash for
+the foreseeable future. During fiscal 2002, the Company expects to have an
+ongoing need to raise cash by securing additional debt or equity financing, or
+by monetizing (divesting) certain assets to fund its operations until they
+return to profitability and positive operating cash flow.
+The Company is currently considering the sale and leaseback of its principal
+operating facilities in Anaheim, California and is in negotiations with a
+financial institution to provide a new line of credit. However, the Company
+cannot be certain that its plan to sell and leaseback of its facilities will be
+successful, that it will be able to secure a new line of credit on terms
+acceptable to us, or at all, or that its existing lender will continue to
+extend its existing borrowing relationship. The Company's future cash
+requirements will be highly dependent on its ability to control expenses as
+well as the successful execution of the revenue plans by each of our
+businesses. As a result, any projections of future cash requirements and cash
+flows are subject to substantial uncertainty.
+These conditions raise substantial doubt about the Company's ability to
+continue as a going concern. The accompanying consolidated financial statements
+do not include any adjustments to reflect the possible future
+F-8
+ODETICS, INC.
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
+effects on the recoverability and classification of assets or liabilities that
+may result from the outcome of this uncertainty.
+2. Summary of Significant Accounting Policies
+Principles of Consolidation
+The accompanying consolidated financial statements include the accounts of
+the Company and its subsidiaries. All significant intercompany accounts and
+transactions have been eliminated in consolidation.
+Use of Estimates
+The preparation of financial statements in conformity with generally
+accepted accounting principles requires management to make estimates and
+assumptions that affect the amounts reported in the financial statements and
+accompanying notes. Actual results could differ from those estimates.
+Significant estimates made in preparing the consolidated financial statements
+include the allowances for doubtful accounts and deferred tax assets, inventory
+reserves, certain accrued liabilities, costs to complete long-term contracts
+and estimates of future cash flows used to determine the recoverability of long
+lived assets.
+Revenue Recognition
+Product revenues and related cost of sales are recognized on the date of
+shipment or, if required, upon acceptance by the customer, provided that the
+Company believes collectibility of the net sales amount is probable.
+Accordingly, at the date revenue is recognized, the significant uncertainties
+concerning the sale have been resolved.
+Contract revenues is derived primarily from long-term contracts with
+governmental agencies. Contract revenue includes costs incurred plus a portion
+of estimated fees or profits determined on the percentage of completion method
+of accounting based on the relationship of costs incurred to total estimated
+costs. Any anticipated losses on contracts are charged to earnings when
+identified. Changes in job performance and estimated profitability, including
+those arising from contract penalty provisions and final contract settlements
+may result in revisions to cost and revenue and are recognized in the period in
+which the revisions are determined. Profit incentives are included in revenue
+when their realization is reasonably assured.
+Certain products sold by the Company include software which is integral to
+the functionality of the product. When such products do not require significant
+production, modification or customization of the software, revenue is
+recognized upon delivery, assuming the fee is fixed and collectibility is
+probable. If an arrangement requires significant production, modification or
+customization of the software, the arrangement is accounted for on the
+percentage of completion method of accounting as costs are incurred.
+Revenues from follow-on service and support, for which the Company charges
+separately, are recognized when earned. Revenues from computer software
+maintenance agreements are recognized ratably over the term of the agreements.
+When computer software maintenance is included in a software license agreement,
+an appropriate portion of the license fee is deferred and recognized over the
+maintenance period.
+Cash and Cash Equivalents
+Cash and cash equivalents consist of cash and short-term investments with
+maturities of less than ninety days.
+F-9
+ODETICS, INC.
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
+Concentration of Credit Risk
+The Company performs periodic credit evaluations of its customers'
+financial condition and generally does not require collateral. Credit losses
+have been within management's expectations and within amounts provided through
+the allowances for doubtful accounts. At March 31, 2000 and 2001, accounts
+receivable from governmental agencies and prime government contractors were
+approximately $3,639,000 and $3,719,000, respectively.
+Fair Values of Financial Instruments
+Fair values of cash and cash equivalents, and the current portion of long-
+term debt approximate the carrying value because of the short period of time
+to maturity. The fair value of long-term debt approximates carrying value
+because the related rates of interest approximate current market rates and has
+variable rates of interest.
+Inventory Valuation
+Inventories are stated at the lower of cost or market. Cost is determined
+on the first-in, first-out method.
+Property, Plant and Equipment
+Property, plant and equipment are recorded at cost. Buildings are
+depreciated using the straight-line method over their estimated useful lives
+up to a period of forty years. Equipment, furniture and fixtures, including
+assets recorded under capital lease obligations, are depreciated principally
+by the declining balance method over their estimated useful lives ranging from
+four to eight years.
+Long-Lived Assets
+Long-lived assets and certain identifiable intangibles held and used by the
+Company are reviewed for impairment whenever events or changes in
+circumstances indicate that the carrying amount of an asset may not be
+recoverable. The Company believes no impairment of the carrying value of its
+long-lived assets, inclusive of goodwill, existed at March 31, 2001. The
+Company's analysis was based on an estimate of future undiscounted cash flows
+using forecasts contained in the Company strategic plan. It is at least
+reasonably possible that the Company's estimate of future undiscounted cash
+flows may change during fiscal 2002. If the Company's estimate of future
+undiscounted cash flow should change or if the strategic plan is not achieved,
+future analyses may indicate insufficient future undiscounted cash flows to
+recover the carrying value of the Company's long-lived assets, in which case
+such assets would be written down to estimated fair value.
+Goodwill
+Goodwill, representing the excess of the purchase price over the fair value
+of the net assets of acquired entities, is being amortized using the straight-
+line method over the estimated useful lives ranging from three to fifteen
+years.
+Research and Development Expenditures
+Software development costs incurred subsequent to determination of
+technical feasibility are capitalized. Amortization of capitalized software
+costs is provided on a product-by-product basis at the greater of the amount
+computed using (a) the ratio of current gross revenues for the product to the
+total of current and anticipated future gross revenues or (b) the straight-
+line method over the remaining estimated economic life of the product.
+Amortization begins when product is available for general release to
+customers. Generally, an original estimated economic life of two to five years
+is assigned to capitalized software development costs.
+F-10
+ODETICS, INC.
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
+During fiscal 1999, 2000 and 2001, software development costs were amortized
+to cost of sales totaling $1,063,000, $1,515,000 and $940,000, respectively.
+During fiscal 2001, the Company discontinued certain product lines, resulting
+in the write-off of $3.5 million of previously capitalized software development
+costs (Note 4).
+All other research and development expenditures are charged to expense in
+the period incurred.
+Warranty
+The Company provides a warranty of one to two years on all products and
+records a related provision for estimated warranty costs at the date of the
+sale. The estimated warranty liability at March 31, 2000 and 2001 was $596,000
+and $389,000, respectively.
+Comprehensive Income (Loss)
+Statement of Financial Accounting Standards No. 130, establishes standards
+for reporting and displaying comprehensive income (loss) and its components in
+the consolidated financial statements. For the Company, the only component of
+accumulated other comprehensive income (loss) is the cumulative foreign
+currency translation adjustment recorded in stockholders' equity.
+Income Taxes
+Deferred income tax assets and liabilities are computed for differences
+between financial statement and tax basis of assets and liabilities based on
+enacted tax laws and rates applicable to the period in which differences are
+expected to affect taxable income. Valuation allowances are established when
+necessary to reduce deferred tax assets to amounts which are more likely than
+not to be realized. The provision for income taxes is the taxes payable or
+refundable for the period plus or minus the change during the period in
+deferred income tax assets and liabilities.
+Loss Per Share
+Basic and diluted loss per share is computed using the weighted average
+number of shares of common stock outstanding during the year and excludes the
+anti-dilutive effects of options.
+Stock Compensation
+The Company has elected to follow Accounting Principles Board Opinion No.
+25, Accounting for Stock Issued to Employees (APB 25) and related
+Interpretations in accounting for its employee stock options because the
+alternative fair value accounting provided for under Statement of Financial
+Accounting Standard No. 123, Accounting for Stock-Based Compensation
+("Statement 123"), requires use of option valuation models that were not
+developed for use in valuing employee stock options. Under APB 25, if the
+exercise price of the Company's employee stock options equals the market price
+of the underlying stock on the date of grant, no compensation expense is
+recognized.
+In March 2000, the Financial Accounting Standards Board issued
+Interpretation No. 44, Accounting for Certain Transactions Involving Stock
+Compensation - an interpretation of APB Opinion No. 25 ("FIN 44"). FIN 44
+clarifies the definition of employee for purposes of applying Accounting
+Practice Board Opinion No. 25, Accounting for Stock Issued to Employees, the
+criteria for determining whether a plan qualifies as a
+F-11
+ODETICS, INC.
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
+noncompensatory plan, the accounting consequence of various modifications to
+the terms of a previously fixed stock option or award, and the accounting for
+an exchange of stock compensation awards in a business combination. FIN 44 is
+effective July 1, 2000, but certain conclusions cover specific events that
+occur after either December 15, 1998, or January 12, 2000. The adoption of FIN
+44 did not have a material effect on the Company's financial position or
+results of operations.
+To calculate the pro forma information required by Statement 123, the
+Company uses the Black-Scholes option pricing model. The Black-Scholes model
+was developed for use in estimating the fair value of traded options which have
+no vesting restrictions and are fully transferable. In addition, option
+valuation models require the input of highly subjective assumptions including
+the expected stock price volatility. Because the Company's employee stock
+options have characteristics significantly different from those of traded
+options, and because changes in the subjective input assumptions can materially
+affect the fair value estimate, in management's option, the existing models do
+not necessarily provide a reliable single measure of the fair value of its
+employee stock options.
+Advertising Expenses
+The Company expenses advertising costs as incurred. Advertising expense
+totaled $2,622,000, $2,488,000 and $3,491,000 in the years ended March 31,
+1999, 2000 and 2001, respectively.
+Derivative Instruments and Hedging Activities
+In June 1998 Statement of Financial Accounting Standard No. 133, Accounting
+for Derivative Instruments and Hedging Activities ("Statement 133"), was
+issued, which establishes new standards for recording derivatives in financial
+statements. This statement requires recording all derivative instruments as
+assets or liabilities, measured at fair value. Statement 133, as amended, is
+effective for fiscal years beginning after June 15, 2000. Management does not
+anticipate the adoption of this statement will have a significant impact on the
+consolidated results of operations or financial position of the Company.
+Reclassifications
+Certain amounts in the 1999 and 2000 consolidated financial statements have
+been reclassified to conform with the 2001 presentation.
+3. Acquisitions and Dispositions
+On September 12, 1998, the Company acquired International Media Integration
+Services Limited, a United Kingdom corporation (IMIS), pursuant to the terms of
+a Sale and Purchase of Shares Agreement whereby the Company purchased all of
+the issued and outstanding shares of stock of IMIS for an aggregate purchase
+price of $970,000 which was paid in 173,214 shares of the Company's Class A
+common stock. The acquisition has been accounted for as a purchase, and the
+purchase price has been allocated to the fair value of the net assets acquired,
+primarily acquired technology, which is being amortized over its expected
+useful life of 5 years.
+On October 16, 1998, the Company, through its subsidiary, Iteris, Inc.,
+acquired Meyer, Mohaddes Associates, Inc., a provider of transportation,
+engineering and planning services (MMA). Pursuant to the terms of the merger
+agreement, the Company purchased all of the issued and outstanding shares of
+stock of MMA for $4.3 million, by issuing 55,245 shares of the Company's Class
+A common stock valued at $250,000 and 810,153 shares of Iteris, Inc.'s common
+stock after giving effect to the purchase price adjustment required by the
+merger agreement and a 1.874916-to-1 split of Iteris common stock. The results
+of operations of MMA are included in the Company's consolidated results of
+operations from the date of acquisition.
+F-12
+ODETICS, INC.
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
+The merger agreement provided for MMA shareholders to receive additional
+shares of the Company's Class A common stock with a then market value of
+$250,000 at each of April 16, 1999, October 16, 1999, April 16, 2000, October
+16, 2000 and April 16, 2001 in the event the Company did not consummate an
+initial public offering of the common stock of Iteris, Inc. by each and any of
+those dates. Pursuant to this provision, Odetics issued an additional 164,461
+shares of its Class A common stock to the MMA shareholders through April 16,
+2001, which was recorded by the Company as additional goodwill. In addition, if
+Iteris does not complete its initial public offering by October 2001, then the
+holders of the Iteris common stock issued in this transaction will have the
+right to require Odetics to repurchase the Iteris common stock for a purchase
+price of $10 per share of Iteris. At any time prior to the initial public
+offering of Iteris, Odetics has the right to require these shareholders to sell
+all of their shares of Iteris common stock at a purchase price of $10 per
+share. Odetics has the option to pay the purchase price for theses shares in
+cash or in Odetics' Class A common stock valued as of five business days prior
+to the date of the event triggering the payment.
+On January 19, 1999, the Company, through its subsidiary, Iteris, Inc.,
+acquired certain assets and assumed certain liabilities of Viggen Corporation,
+a provider of transportation, engineering and planning services, for an
+aggregate purchase price of $275,000 evidenced by the issuance of 27,603 shares
+of the Company's Class A common stock which were issued in April 1999. The
+acquisition has been accounted for as a purchase and the purchase price,
+including direct costs of the acquisition, has been allocated to the fair value
+of the net assets acquired with the excess approximating $746,000 allocated to
+goodwill. The results of operations of Viggen are included in the Company's
+consolidated results of operations from the date of acquisition.
+On December 1, 1999, the Company through its wholly owned subsidiary, Gyyr,
+Inc., acquired the security products division of Digital Processing Systems,
+Inc. (DPS), a manufacturer of digital security recorder products. Pursuant to
+the terms of the Asset Purchase Agreement, the Company purchased certain assets
+and assumed certain liabilities of DPS for an aggregate purchase price of
+approximately $3.5 million. The Company paid $1.5 million on December 1, 1999
+and $1 million on December 1, 2000. The final payment of $1 million is due on
+December 1, 2001. This acquisition was accounted for as a purchase and
+accordingly, the result of operations for DPS are included in the Company's
+consolidated results of operations from the date of acquisition. The excess of
+cost over the fair value of the net assets of approximately $3.4 million has
+been recorded as goodwill.
+During fiscal 2001, the Company sold certain assets of its sold state
+recording product line and of its Zyfer subsidiary for cash proceeds of $1.9
+million. In connection with these sales the Company recorded gains aggregating
+$1.2 million.
+Pro forma information related to these transactions is not material to the
+Company's historical consolidated results of operations.
+4. Special Charge
+During fiscal 2001, the Company approved a number of actions to reduce
+operating expenses and improve profitability and cash flows. These actions
+included a reduction in workforce of 104 employees and the discontinuance of
+certain product lines. As a result of these actions the company recorded the
+following as special charge (in thousands):
+Severance and related costs.......................................... $1,305
+Write-off of capitalized software.................................... 3,452
+Write-off of goodwill................................................ 562
+Write-off deferred costs............................................. 966
+------
+$6,285
+======
+F-13
+ODETICS, INC.
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
+In addition, the Company reserved or wrote-off inventory in the amount of
+$3.1 million, primarily related to discontinued products in its Broadcast and
+Gyyr subsidiaries. This charge is included in cost of sales in the accompanying
+consolidated statement of operations.
+5. Related Party Transaction
+In July 1999, the Company sold an option to an investment company controlled
+by certain officers and shareholders of the Company, for an aggregate purchase
+price of $5.0 million to purchase certain real property of Odetics. In August
+2000 the Company repurchased the option for $5.6 million which represented the
+original purchase price plus accrued interest.
+6. Costs and Estimated Earnings on Uncompleted Contracts
+Costs incurred, estimated earnings and billings on uncompleted long-term
+contracts are as follows:
+March 31
+---------------
+2000 2001
+------- -------
+(In thousands)
+Costs incurred on uncompleted contracts..................... $21,971 $14,054
+Estimated earnings.......................................... 1,648 1,054
+------- -------
+23,619 15,108
+Less billings to date....................................... 21,639 14,387
+------- -------
+$ 1,980 $ 721
+======= =======
+Included in accompanying balance sheets:
+Costs and estimated earnings in excess of billings on
+uncompleted contracts.................................... $ 3,283 $ 3,296
+Billings in excess of costs and estimated earnings on
+uncompleted contracts.................................... 1,303 2,575
+------- -------
+$ 1,980 $ 721
+======= =======
+Costs and estimated earnings in excess of billings at March 31, 2000 and
+2001 include $150,000 and $232,575, respectively, that were not billable as
+certain milestone objectives specified in the contracts had not been attained.
+Substantially all costs and estimated earnings in excess of billings at March
+31, 2001 are expected to be billed and collected during the year ending March
+31, 2002.
+7. Revolving Line of Credit and Long-Term Debt
+In December 1998, the Company entered into a $17.0 million revolving line of
+credit, which provided for borrowings at the prime rate plus 2.0% (9.0% at
+March 31, 2001). The revolving line of credit is collateralized by
+substantially all of the Company's assets. Under the terms of the loan and
+security agreement, the Company is required to comply with certain covenants,
+maintain certain debt to net worth ratios, working capital current ratios and
+minimum net worth requirements, and prohibits the payment of dividends without
+the lender's consent. As amended, the line of credit expires on July 31, 2001
+(Note 1).
+On January 25, 2000, the Company through its subsidiary, Iteris, Inc.,
+entered into a joint venture agreement, pursuant to which the Company obtained
+a Subordinated Convertible Promissory Note in the amount of $3.75 million. The
+note is convertible into Iteris' common stock either at the option of the joint
+venture partner at any time prior to the maturity, or automatically upon an
+initial public offering of Iteris' common stock or a change in control event,
+as defined in the agreement. The number of shares issuable upon conversion is
+subject to the fair value of the Iteris's common stock on the date of
+conversion. The note matures on January 25, 2002 and bears interest at 8.0% per
+annum. All accrued interest will be forgiven if the conversion feature is
+triggered.
+F-14
+ODETICS, INC.
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
+Long-term debt consisted of the following:
+March 31
+--------------
+2000 2001
+------- ------
+(In thousands)
+Note payable, accruing interest at 9.36%, collateralized by
+deed of trust on land and buildings with a net book value of
+approximately $14.4 million, paid in May 2001 (Note 1)...... $ 7,027 $5,874
+Notes payable, accruing interest at 8.00%, payable upon
+maturity in January 2002.................................... 3,750 3,750
+Note payable, in two equal annual installments in December
+2001 and 2002............................................... 2,000 1,000
+Notes payable, accruing interest at 7.55% to 17.08%,
+collateralized by equipment, payable in monthly installments
+through 2003................................................ 1,991 1,166
+------- ------
+14,768 11,790
+Less current portion......................................... 3,102 6,990
+------- ------
+$11,666 $4,800
+======= ======
+The annual maturities of long-term debt through March 31, 2005 are as
+follows:
+(In thousands)
+2002.......................................................... $ 6,990
+2003.......................................................... 1,804
+2004.......................................................... 1,653
+2005.......................................................... 1,343
+-------
+$11,790
+=======
+8. Income Taxes
+The reconciliation of the income tax benefit from continuing operations to
+taxes computed at U.S. federal statutory rates is as follows:
+Year ended March 31
+-------------------------
+1999 2000 2001
+------- ------ --------
+(In thousands)
+Income tax benefit at statutory rates............ $(6,840) $ (775) $(11,064)
+Increase (decrease) of valuation allowance ...... 5,373 (773) 8,353
+Foreign losses recorded without benefit.......... 1,061 1,258 2,255
+Nondeductible goodwill amortization.............. 31 191 153
+Other............................................ 375 99 303
+------- ------ --------
+$ -- $ -- $ --
+======= ====== ========
+F-15
+ODETICS, INC.
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
+United States and foreign loss from continuing operations before income
+taxes are as follows:
+Year ended March 31
+---------------------------
+1999 2000 2001
+-------- ------- --------
+(In thousands)
+Pretax (income) loss:
+Domestic...................................... $(16,997) $ 1,317 $(25,918)
+Foreign....................................... (3,121) (3,596) (6,622)
+-------- ------- --------
+$(20,118) $(2,279) $(32,540)
+======== ======= ========
+Significant components of the income taxes benefit from continuing
+operations are as follows:
+Year ended March
+31
+------------------
+1999 2000 2001
+----- ----- -----
+(In thousands)
+Current:
+Federal................................................. $(915) $ -- $ --
+State................................................... -- -- --
+Foreign................................................. -- -- --
+----- ----- -----
+Total current......................................... (915) -- --
+Deferred: -- -- --
+Federal................................................. 915 -- --
+State................................................... -- -- --
+Foreign................................................. -- -- --
+----- ----- -----
+Total deferred........................................ 915 -- --
+----- ----- -----
+$ -- $ -- $ --
+===== ===== =====
+The components of deferred tax assets and liabilities are as follows:
+2000 2001
+------- --------
+(In thousands)
+Deferred tax assets:
+Inventory reserves...................................... $ 730 $ 738
+Deferred compensation and other payroll accruals........ 1,016 1,074
+Net operating loss carryover............................ 4,417 14,578
+Credit carryforwards.................................... 1,519 2,051
+Bad debt and other reserves............................. 1,120 1,300
+Other, net.............................................. 400 281
+------- --------
+Total deferred tax assets................................. 9,202 20,022
+Valuation allowance for deferred tax assets............... (6,145) (17,378)
+------- --------
+Net deferred tax assets................................... 3,057 2,644
+------- --------
+Deferred tax liabilities:
+Tax over book depreciation.............................. 1,973 1,990
+Capitalized interest and taxes.......................... 451 434
+Cash to accrual adjustment.............................. 347 174
+Other, net.............................................. 286 46
+------- --------
+Total deferred tax liabilities............................ 3,057 2,644
+------- --------
+Net deferred taxes........................................ $ -- $ --
+======= ========
+F-16
+ODETICS, INC.
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
+At March 31, 2001, for federal income tax purposes, the Company had
+approximately $1,238,000 in general business credit carryforwards and $534,000
+of alternative minimum tax credit carryforwards. The Company also has
+$37,096,000 of net operating loss carryforwards for federal income tax purposes
+which begin to expire in 2019, and $640,000 of net operating loss carryfowards
+which were acquired as part of the ICI acquisition. For financial reporting
+purposes, a valuation allowance has been recorded to offset the deferred tax
+asset related to these credits and net operating losses. Any future benefits
+recognized from the reduction of the valuation allowance related to these
+carryforwards will result in a reduction of income tax expense, other than the
+ICI operating loss carryforwards realization of which will result in an
+adjustment of assets acquired in this acquisition. The business credit
+carryforwards expire at various dates beginning in 2002 and the acquired net
+operating losses begin to expire in 2003.
+Because of the "change of ownership" provision of the Tax Reform Act of
+1986, utilization of the Company's net operating loss carryforwards may be
+subject to an annual limitation against taxable income in future periods. As a
+result of the annual limitation, a portion of these carryforwards may expire
+before ultimately becoming available to reduce future income tax liabilities.
+9. Associate Incentive Programs
+Under the terms of a Profit Sharing Plan, the Company contributes to a trust
+fund such amounts as are determined annually by the Board of Directors. No
+contributions were made in 1999, 2000 or 2001.
+In May 1990, the Company adopted a 401(k) Plan as an amendment and
+replacement of the former Associate Stock Purchase Plan that was an additional
+feature of the Profit Sharing Plan. Under the 401(k) Plan, eligible associates
+voluntarily contribute to the plan up to 15% of their salary through payroll
+deductions. The Company matches 50% of contributions up to a stated limit.
+Under the provisions of the 401(k) Plan, associates have four investment
+choices, one of which is the purchase of Odetics, Class A common stock at
+market price. Company matching contributions were approximately $644,000,
+$677,000 and $795,000 in 1999, 2000 and 2001, respectively.
+Effective April 1, 1987, the Company established a noncontributory Associate
+Stock Ownership Plan (ASOP) for all associates with more than six months of
+eligible service. The ASOP provides that Company contributions, which are
+determined annually by the Board of Directors, may be in the form of cash or
+shares of Company stock. The Company contributions to the ASOP were
+approximately $55,000, $69,000 and $17,000 in 1999, 2000 and 2001,
+respectively. Shares distributed through the ASOP Plan were included in total
+outstanding shares used in the earnings per share calculation.
+10. Deferred Compensation Plans
+During 1986, the Company adopted an Executive Deferral Plan under which
+certain executives may defer a portion of their annual compensation. All
+deferred amounts earn interest, generally with no guaranteed rate of return.
+Compensation charged to operations and deferred under the plan totaled
+$377,000, $110,000 and $128,000 for 1999, 2000 and 2001, respectively.
+11. Stock Option Plans
+The Company has adopted an Associate Stock Option Plan which provides that
+options for shares of the Company's unissued Class A common stock may be
+granted to directors and associates of the Company. Options granted enable the
+option holder to purchase one share of Class A common stock at prices which are
+equal to or greater than the fair market value of the shares at the date of
+grant. Options expire ten years after
+F-17
+ODETICS, INC.
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
+date of grant or 90 days after termination of employment and vest ratably at
+33% on each of the first three anniversaries of the grant date.
+A summary of all Company stock option activity is as follows:
+Year ended March 31
+--------------------------------------------------
+1999 2000 2001
+---------------- ---------------- ----------------
+Weighted Weighted Weighted
+Average Average Average
+Exercise Exercise Exercise
+Options Price Options Price Options Price
+------- -------- ------- -------- ------- --------
+(In thousands, except per share data)
+Options outstanding at
+beginning of year......... 563 $4.67 628 $ 5.27 801 $ 7.68
+Granted.................. 149 7.36 358 10.36 120 13.47
+Exercised................ (59) 4.63 (152) 4.65 24 7.95
+Canceled................. (25) 4.63 (33) 4.65 93 8.21
+--- ---- ---
+Options outstanding at end
+of year................... 628 5.27 801 7.68 804 8.44
+=== ==== ===
+Exercisable at end of
+year...................... 165 219 531
+=== ==== ===
+Available for grant at end
+of year................... 37 114 487
+=== ==== ===
+Weighted average fair value
+of options granted........ $3.81 $ 5.25 $ 7.03
+===== ====== ======
+The exercise price for options outstanding as of March 31, 2001, ranged from
+$4.50 to $15.625. The weighted-average remaining contractual life of those
+options is 8.0 years.
+Pro Forma Disclosures of the Effect of Stock-Based Compensation Plans
+In calculating pro forma information regarding net income and earning per
+share, as required by Statement No. 123, the fair value was estimated at the
+date of grant using a Black-Scholes option pricing model with the following
+assumption:
+Years ended March 31
+----------------------
+1999 2000 2001
+------ ------ ------
+Dividend rate........................................... 0.0 0.0 0.0
+Expected life--years.................................... 7.0 7.0 7.0
+Risk-free interest rate................................. 6.0 6.0 6.0
+Volatility of common stock.............................. 0.4 0.4 0.4
+F-18
+ODETICS, INC.
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
+For purposes of pro forma disclosures, the estimated fair value of the
+options is amortized to expense over the options' vesting period. The Company's
+pro forma information for the year ended March 31, 1999, 2000 and 2001 follows
+(in thousands, except per share data):
+1999 2000 2001
+-------- ------- ---------
+Pro forma:
+Net loss.................................... $(20,555) $(2,969) $(33,512)
+Basic and diluted loss per share............ $ (2.63) $ (0.33) $ (3.36)
+Iteris, Inc.'s Stock Options
+In September 1997, Iteris granted options to purchase up to 899,960 shares
+of its common stock to certain members of its senior management at an exercise
+price of $1.07 per share. The options granted vested ratably at 25% on each of
+the first four anniversaries of the grant date.
+Subsequently, Iteris' Board of Directors adopted and approved the 1998 Stock
+Incentive Plan (the "Plan"), as amended in February 2000, authorized 3,000,000
+shares of Iteris' common stock for issuance under the Plan. Options to purchase
+1,731,485 shares of common stock, at exercise prices ranging from $1.60 to
+$9.07 per share, were outstanding at March 31, 2001. Options expire ten years
+after date of grant or 90 days after termination of employment. The options
+granted vested ratably at 25% on each of the first four anniversaries of the
+grant date.
+Mariner Networks, Inc.'s Stock Options
+In March 2000, Mariner's Board of Directors adopted a Special Executive
+Stock Option Plan which provides for the granting of stock options for shares
+of Mariner's unissued common stock to certain officers, key employees, non-
+employee members of the Board of Directors, consultants and independent
+contractors. A total of 1,500,000 shares of Mariner's common stock are reserved
+for issuance under this plan.
+In March 2000, Mariner's Board of Directors also adopted the 1999 Employee
+Stock Option Plan which provides options for shares of Mariner's common stock
+to associates, non-employee members of the Board of Directors of Mariner,
+Odetics or other Odetics' subsidiaries and independent consultants. A total of
+1,000,000 shares of Mariner's common stock are reserved for issuance under this
+plan.
+Options expire ten years after date of grant or 90 days after termination of
+employment and vest upon the optionee's completion of five years of service
+measured from the vesting commencement date as specified on the stock option
+agreements. The vesting of these options will accelerate upon initial public
+offering of Mariner's common stock. Options to purchase 1,727,250 shares of
+Mariner's common stock were outstanding at March 31, 2001 under these plans.
+Zyfer, Inc.'s Stock Option Plans
+In April 2000, Zyfer's Board of Directors adopted a Special Executive Stock
+Option Plan which provides for the granting of stock options for shares of
+Zyfer's unissued common stock to certain officers, key employees, non-employee
+members of the Board of Directors, consultants and independent contractors. A
+total of 1,176,500 shares of Zyfer's common stock are reserved for issuance
+under this plan.
+In April 2000, Zyfer's Board of Directors also adopted the 1999 Employee
+Stock Option Plan which provides options for shares of Zyfer's common stock to
+associates, non-employee members of the Board of Directors of Zyfer, Odetics or
+other Odetics' subsidiaries and independent consultants. A total of 588,500
+shares of Zyfer's common stock are reserved for issuance under this plan.
+19
+ODETICS, INC.
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
+Options expire ten years after date of grant or 90 days after termination of
+employment and vest upon the optionee's completion of five years of service
+measured from the vesting commencement date as specified on the stock option
+agreements. The vesting of these options will accelerate upon initial public
+offering of Zyfer's common stock. Options to purchase 885,000 shares of Zyfer's
+common stock were outstanding at March 31, 2001.
+12. Commitments
+The Company has lease commitments for facilities in various locations
+throughout the United States. The annual commitment under these noncancelable
+operating leases at March 31, 2001 is as follows:
+Fiscal Year
+-----------
+(in thousands)
+2002....................................................... $307
+2003....................................................... 121
+2004....................................................... 35
+----
+$463
+====
+Rent expense under operating leases totaled $725,000, $973,000 and
+$1,040,000, respectively for the years ended March 31, 1999, 2000 and 2001.
+13. Business Segment and Geographic Information
+The Company operates in three reportable segments: intelligent
+transportation systems, video products which includes products for the
+television broadcast and video security markets, and telecommunications. The
+accounting policies of the reportable segments are the same as those described
+in the summary of significant accounting policies except that certain expenses,
+such as interest, amortization of certain intangibles and certain corporate
+expenses are not allocated to the segments. In addition, certain assets
+including cash and cash equivalents, deferred taxes and certain long-lived and
+intangible assets are not allocated to the segments. Intersegment sales are
+recorded at the selling segment's cost plus profit.
+The reportable segments are each managed separately because they manufacture
+and distribute distinct products or provide services with different processes.
+F-20
+ODETICS, INC.
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
+Selected financial information for the Company's reportable segments as of
+and for the years ended March 31, 1999, 2000 and 2001 follows:
+Intelligence Video Telecom
+Transportation Products Product Total
+-------------- -------- -------- --------
+(In thousands)
+Year ended March 31, 1999
+Revenue from external customers.. $14,580 $ 46,755 $ 13,974 $ 75,309
+Intersegment revenues............ -- 5,351 94 5,445
+Depreciation and amortization.... 765 2,282 1,199 4,246
+Segment income (loss)............ (3,865) (5,381) (2,617) (11,863)
+Segment assets................... 17,943 38,831 8,954 65,728
+Expenditure for long-lived
+assets.......................... 4,924 3,457 3,084 11,465
+Year ended March 31, 2000
+Revenue from external customers.. $23,411 $ 38,958 $ 9,664 $ 72,033
+Intersegment revenues............ -- 6,001 84 6,085
+Depreciation and amortization.... 1,962 2,637 1,182 5,781
+Segment income (loss)............ (4,407) (16,350) (7,824) (28,581)
+Segment assets................... 19,240 38,831 8,954 67,025
+Expenditure for long-lived
+assets.......................... 470 760 1,108 2,338
+Year ended March 31, 2001
+Revenue from external customers.. $28,057 $ 39,726 $ 7,883 $ 75,666
+Intersegment revenues............ -- 1,183 57 1,240
+Depreciation and amortization.... 1,502 2,513 447 4,462
+Segment income (loss)............ (3,942) (15,767) (14,042) (33,751)
+Segment assets................... 18,709 22,706 11,965 53,380
+Expenditure for long-lived
+assets, net..................... 1,392 631 506 2,529
+F-21
+ODETICS, INC.
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
+The following reconciles segment income to consolidated income before income
+taxes and segment assets and deprecation and amortization to consolidated
+assets and consolidated depreciation and amortization:
+1999 2000 2001
+-------- -------- --------
+(In thousands)
+Revenue
+Total revenues for reportable segments........... $ 80,754 $ 78,118 $ 76,906
+Non reportable segment revenues.................. 8,064 8,673 1,403
+Elimination of Intersegment sales................ (5,445) (6,084) (1,240)
+-------- -------- --------
+Total consolidated revenues.................. $ 83,373 $ 80,707 $ 77,069
+======== ======== ========
+Segment Profit or Loss
+Total profit or loss for reportable segments..... $(11,863) $(28,581) $(33,751)
+Other profit or loss............................. (1,201) (3,618) (2,893)
+Unallocated amounts:
+Corporate and other expenses................... (5,247) (6,469) (5,674)
+Royalty income................................. -- 38,437 17,825
+Special charge................................. -- -- (6,285)
+Interest expense............................... (1,807) (2,048) (1,762)
+-------- -------- --------
+Loss from continuing operations before income
+taxes....................................... $(20,118) $ (2,279) $(32,540)
+======== ======== ========
+Assets
+Total assets for reportable segments............. $ 65,728 $ 67,025 $ 53,380
+Assets held at Corporate......................... 15,627 14,825 14,681
+-------- -------- --------
+Total assets................................. $ 81,355 $ 81,850 $ 68,061
+======== ======== ========
+Depreciation and Amortization
+Depreciation and amortization for reportable
+segments........................................ $ 4,246 $ 5,781 $ 4,462
+Other............................................ 959 1,404 505
+-------- -------- --------
+Total depreciation and amortization.......... $ 5,205 $ 7,185 $ 4,967
+======== ======== ========
+Selected financial information for the Company's operations by geographic
+segment is as follows:
+1999 2000 2001
+------- ------- -------
+(In thousands)
+Geographic Area Revenue
+United States.......................................... $61,171 $65,285 $61,506
+Europe................................................. 7,582 8,509 7,340
+Asia Pacific Rim....................................... 6,287 2,821 2,703
+Other.................................................. 8,333 4,092 5,520
+------- ------- -------
+Total net revenue.................................... $83,373 $80,707 $77,069
+======= ======= =======
+Geographic Area Long-Lived Assets
+United States.......................................... $39,424 $38,805 $33,586
+Europe................................................. 1,612 1,101 414
+Asia Pacific Rim....................................... 33 15 23
+------- ------- -------
+Total long-lived assets.............................. $41,069 $39,921 $34,023
+======= ======= =======
+F-22
+ODETICS, INC.
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
+14. Supplemental Cash Flow Information
+Year ended March 31
+-------------------------
+1999 2000 2001
+------- ------- -------
+(In thousands)
+Net cash used in changes in operating assets and
+liabilities, net of acquisitions:
+(Increase) decrease in accounts receivable....... $(2,706) $ 4,568 $ (882)
+(Increase) decrease in net costs and estimated
+earnings in excess of billings.................. 276 (833) 1,259
+(Increase) decrease in inventories............... 4,825 (2,227) 4,499
+Increase in prepaids and other assets............ 111 428 861
+Increase (decrease) in accounts payable and
+accrued expenses................................ (946) (757) (1,116)
+------- ------- -------
+Net cash used in changes in operating assets and
+liabilities....................................... $ 1,560 $ 1,179 $ 4,621
+======= ======= =======
+Cash paid during the year:
+Interest......................................... $ 1,997 $ 1,995 $ 1,768
+Income taxes paid (refunded)..................... (463) (1,144) 86
+Noncash transactions during the year:
+Purchase of subsidiary for stock................. $ 5,845 $ -- $ --
+Acquisition of business for note payable......... -- 2,000 --
+Stock issuance to former MMA shareholders........ -- 251 500
+15. Legal Proceedings
+On October 11, 1999, the Company settled a patent infringement case it had
+brought against Storage Technology Corporation (StorageTek). Through an
+agreement, StorageTek agreed to pay the Company a license fee totaling $100.0
+million for use of the Company's United States Patent No. 4,779,151. Under the
+agreement, the license fee was payable in three installments: $80.0 million
+upon signing of the agreement, and two annual installments of $10.0 million
+payable in each of October 2000 and 2001. In connection with the initial
+payment, the Company received $38.4 million, net of legal fees and other direct
+expenses, which is reflected in the accompanying consolidated statement of
+operations as royalty income.
+On June 12, 2000, the Company and StorageTek amended the agreement, whereby
+StorageTek agreed to pay a final discounted payment of $17.8 million
+immediately in full settlement of the $20.0 million otherwise due to complete
+the settlement, which is reflected in the accompanying consolidated financial
+statements as royalty income.
+16. Subsequent Event
+In connection with entering into the $16.0 million promissory in May 2001
+(Note 1), the Company granted the lender a warrant to purchase 426,667 shares
+of the Company's Class A common stock at an exercise price of $4.00 per share.
+The warrant expires in May 2006. During the term of the promissory note,
+assuming certain prepayment milestones are not met, the lender will receive
+warrants to purchase up to an additional 426,667 shares of the Company's Class
+A common stock at an exercise price equal to 110% of the then current market
+price. If the Company prepays the note prior to six months following its
+issuance, up to $1.6 million of the principal amount is convertible, at the
+lender's option, into the Company's Class A common stock at a conversion price
+of $4.00 per share.
+F-23
+Schedule II
+Odentics, Inc.
+Valuation and Qualifying Accounts
+Balance at Charged to Charged Balance at
+Beginning Costs and to Deductions End of
+Description of Period Expenses Accounts Describe Period
+----------- ---------- ---------- -------- ---------- ----------
+Year ended March 31,
+1999:
+Deducted from asset
+accounts:
+Allowance for doubtful
+accounts.............. $ 432,000 $ 332,000 $125,000 $ (50,000) $ 839,000
+Reserve for inventory
+obsolescence.......... 2,881,000 1,590,000 0 (1,300,000) 3,171,000
+Year ended March 31, 2000
+Deducted from asset
+accounts:
+Allowance for doubtful
+accounts............... $ 839,000 $1,293,000 $ 0 $ (64,000) $2,068,000
+Reserve for inventory
+obsolescence.......... 3,171,000 1,438,000 0 (1,123,000) 3,486,000
+Year ended March 31, 2001
+Deducted from asset
+accounts:
+Allowance for doubtful
+accounts............... $2.068,000 $ 78,000 $ 0 $ (502,000) $1,644,000
+Reserve for inventory
+obsolescence.......... 3,486,000 4,925,000 0 (4,443,000) 3,968,000
+S-1
\ No newline at end of file
diff --git a/raw/filings/0000350868/2000/0000931763-01-501040/filing_metadata.csv b/raw/filings/0000350868/2000/0000931763-01-501040/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..689f75e01e06041e1f35b2842b47cf2e168edb7e
--- /dev/null
+++ b/raw/filings/0000350868/2000/0000931763-01-501040/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000350868,ITI,"ITERIS, INC.",10-K,2001-07-16,2001-03-31,2001-07-16T04:00:00.000Z,0000931763-01-501040,d10k.txt,ODETICS FORM 10-K FOR PERIOD ENDING 03/31/01,255885,0,0,https://www.sec.gov/Archives/edgar/data/350868/000093176301501040/d10k.txt,https://www.sec.gov/Archives/edgar/data/350868/000093176301501040/,2000,2000,1
diff --git a/raw/filings/0000350868/2000/0000931763-01-501040/item1.txt b/raw/filings/0000350868/2000/0000931763-01-501040/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..23c8e27065842228643ba114695b14ee26119203
--- /dev/null
+++ b/raw/filings/0000350868/2000/0000931763-01-501040/item1.txt
@@ -0,0 +1,883 @@
+ITEM 1. BUSINESS
+General
+Odetics, Inc. was founded in 1969 to supply digital recorders for use in the
+United States space program. We pioneered new designs and standards for digital
+magnetic tape recorders offering high reliability and enhanced performance in
+the adverse environment attendant to space flight. In the 1970s, we broadened
+our information automation product line to include time-lapse videocassette
+recorders for commercial security and surveillance applications, and entered
+the business of manufacturing telecom network synchronization products. Through
+our Gyyr division, we became a leading supplier of time-lapse videotape
+cassette recorders, digital image processing modules and related products used
+in security and surveillance systems. We incorporated our Gyyr division in
+1997, forming a wholly-owned subsidiary, Gyyr Incorporated. In October 1997, we
+expanded Gyyr by acquiring Intelligent Controls Inc., a manufacturer of access
+control products specializing in PC based, remote site and fiber optic
+communications. In December 1999, we acquired the Security Products Division of
+Digital Systems Processing, Inc., which expanded our product line to include
+digital time-lapse recording based on hard disk drive technology.
+Beginning in the late 1970s, we developed and manufactured telecom
+synchronization products in our Communications division. We incorporated our
+Communications division in fiscal 1999 as our wholly-owned subsidiary, Zyfer,
+Inc., as part of our business expansion to develop products for secured
+communications over the Internet.
+Leveraging our expertise in video image processing, we entered into the
+intelligent transportation system ("ITS") business with the introduction of a
+video-based vehicle detection system in 1993. In June 1997, we acquired certain
+assets comprising the Transportation Systems business from Rockwell
+International, creating our ITS division, which expanded our offerings to
+include advanced traffic management systems and advanced traveler information
+systems. We incorporated our ITS division in 1998 as Odetics ITS, Inc. In
+October 1998, we broadened our systems offerings by acquiring Meyer, Mohaddes
+Associates, Inc. In January 2000, we reincorporated Odetics ITS in Delaware and
+changed its name to Iteris, Inc. Meyer, Mohaddes Associates, Inc. currently
+operates as a wholly-owned subsidiary of Iteris, Inc.
+In the early 1980s, we developed the technical expertise to apply automation
+to new commercial applications and established our Odetics Broadcast division.
+We incorporated our Odetics Broadcast division in 1999 as Broadcast, Inc.
+Broadcast develops and manufactures broadcast automation control systems. The
+success of our video tape libraries led us to pursue new applications for
+information automation technologies. In 1991, we introduced an automated tape
+handling subsystem for integration into tape libraries designed for midrange
+computers and client/server networks. In January 1993, we formed a separate
+subsidiary, ATL Products, Inc., to pursue the market for automated tape
+libraries. In March 1997, ATL completed an initial public offering of 1,650,000
+shares of its Class A common stock. We distributed our remaining 82.9% interest
+in ATL to our stockholders in a tax-free distribution in October 1997.
+1
+Today, Odetics serves as a developer of technology-oriented companies, each
+with its own marketplace, customers and products. These operations share a
+common corporate overhead for support for facilities, human resources, benefits
+and certain accounting, finance and executive management services. We are
+pursuing a business strategy to develop each of these business units with the
+ultimate goal of monetizing them for the benefit of our stockholders. While our
+strategy also embodies the tax-free spin-off of our developed companies to our
+stockholders, we cannot assure that we will be able to spin-off any of these
+companies in the near future, if at all.
+We currently define our business segments as video products, telecom
+products and ITS. Our video products segment includes our Broadcast subsidiary
+and our Gyyr subsidiary. Our telecom products segment includes our Zyfer
+subsidiary and our Mariner Networks subsidiary. Our ITS segment consists of our
+Iteris subsidiary. For more information concerning our business segments,
+please see Note 13 of Notes to Consolidated Financial Statements.
+Video Products
+Broadcast, Inc.
+Broadcast develops systems to automate the storage and scheduling of
+commercials, news stories and other television programming recorded on
+videotape and video server storage systems. We believe that enhanced
+operational efficiencies are a principal factor underlying the automation of
+broadcast television stations and satellite uplink operations as the industry
+transitions to digital television. During fiscal 2001, Broadcast began
+transitioning its focus from a hardware-based business to a product offering
+based on proprietary software solutions for broadband video content management
+and delivery to serve broadcast and cable operations.
+We offer software to form powerful integrated systems, including our
+AIRO(TM) automation system. Multi-channel presentation systems, which integrate
+the complete line of our hardware with commonly available broadcast quality
+video disk recorders, are quickly becoming the core business of Broadcast.
+Broadcast is focused on video asset management, including desktop video
+browsing using a network PC architecture, which can be extended to wide area
+network applications and Internet applications.
+Sales, Marketing and Principal Customers. Broadcast sells directly to
+broadcast television stations, satellite uplink operations, and other broadcast
+television and cable television system operators. The sales and marketing
+management for Broadcast is located at our principal facilities in Anaheim,
+California. Broadcast maintains a dedicated field sales force of three persons
+operating in three U.S. sales regions and Canada, and a sales manager for Latin
+America, Europe and Asia. Broadcast also utilizes additional independent
+representative organizations to promote its products in various other foreign
+markets.
+The customers of Broadcast include major television networks such as Fox,
+the Canadian Broadcasting Corporation, CNBC, Euronews, Televisa, Measat
+Broadcast Network Systems, NBC, the PBS Network, Group W Satellite
+Communications, Asia Broadcast Centre, Univision and over 100 independent and
+network-affiliated television stations. Broadcast currently has systems
+installed in over 40 countries.
+Manufacturing and Materials. Broadcast maintains a dedicated manufacturing
+operation located within our Anaheim, California facilities. Our AIRO products
+are serviced primarily in a facility located in Austin, Texas. At our Anaheim
+facility, Broadcast maintains infrastructure to support production and
+inventory control, purchasing, quality assurance, manufacturing and
+engineering.
+Broadcast purchases video servers from Grass Valley Group, Leitch and
+Pinnacle Systems and video switching, conversion and monitoring equipment from
+Grass Valley Group. Broadcast also purchases cabinets and other fabricated
+parts and components from other third party suppliers.
+2
+Gyyr Incorporated
+Gyyr produces analog and digital video products and access control systems
+that meet the security and surveillance needs for a variety of markets
+including banking, commercial/industrial and retail. Gyyr currently operates
+two divisions, Gyyr GCTV Products and Gyyr Electronic Access Controls. Gyyr
+GCTV Products develops and manufactures analog and digital video products and
+focuses on developing innovative solutions for digital storage assistance based
+video surveillance. Gyyr's time-lapse VCRs are installed in automated teller
+machines and retail point of sale systems to record transaction information in
+an effort to deter and address incidents of theft and other crimes. Gyyr
+Electronic Access Controls develops and manufactures enterprise security
+management systems and focuses on developing network-based access control
+products. Gyyr's access control systems offer managed access and monitoring of
+public, private and high security facilities. Customer demand for more
+sophisticated capabilities and integration due to digital technology has also
+contributed to the recent growth in the market for Gyyr's products. Gyyr's
+strategy is to provide complete software-based system integration of digital
+security devices over a variety of network topologies and the Internet. Recent
+additions to Gyyr's product offerings include network and Internet-based video
+and device control, and video multiplexing and digital recording. In December
+1999, we expanded our product line to include the DVMS family of digital time-
+lapse recorders based on hard disk drive architecture. This product line
+expansion was the result of our acquisition of the Security Products Division
+of Digital Systems Processing, Inc. We sell our products as individual devices
+as well as components of fully-integrated network security control systems.
+Sales, Marketing and Principal Customers. Gyyr markets and sells its
+products through three established channels: OEMs, independent distributors and
+system integrators. Gyyr personnel located at our principal facilities and
+sales offices throughout the world oversee approximately 1,000 of these channel
+partners. Gyyr has a business development and service organization located at
+our Odetics Europe Limited subsidiary. Through January 2000, Odetics Europe
+Limited assisted Gyyr with management in the development of European, Middle
+East and African markets. Commencing in January 2000, Gyyr formed Gyyr Europe
+Limited to succeed Odetics Europe Limited in its support services. Its Asian
+sales and marketing activities are managed from our Anaheim, California
+facilities. Gyyr's principal customers include major security equipment
+companies such as Diebold, Inc., ADT Security Systems, Inc., Honeywell, Inc.,
+Mosler, Inc., Hamilton Safe and ADI.
+Manufacturing and Materials. Gyyr maintains a dedicated manufacturing area
+located within our principal facilities in Anaheim, California. Gyyr primarily
+uses continuous demand flow techniques in its assembly lines. Gyyr maintains
+infrastructure to support production and inventory control, purchasing, quality
+assurance and manufacturing engineering.
+Gyyr purchases substantially all of its VCRs through Nissei Sangyo America,
+the United States distribution affiliate of Hitachi, Ltd., into which we
+incorporate certain value-added features. As a result of its reliance on
+Hitachi, Ltd, Gyyr is vulnerable to Hitachi's actions, which might necessitate
+changes in the design or manufacturing of Gyyr's products. While other
+suppliers are available who can manufacture VCRs suitable for use in Gyyr's
+products, we would be required to make changes in our product design or
+manufacturing methods to accommodate other VCRs, and Gyyr could experience
+delays or interruptions in supply while these changes are incorporated or a new
+supplier is procured.
+Telecom Products
+Zyfer, Inc.
+We incorporated our Communications division in 1999 as Zyfer, Inc. Zyfer
+develops and manufactures telecom network synchronization products and provides
+service support for space borne digital data recorders. Our telecom network
+synchronization products synchronize communications for data security, timing
+networks and wireless communications systems. These products are based on GPS
+and oscillator technologies and are sold for new applications in wireless
+networks and satellite communications for both commercial and government
+customers. Significant customers of Zyfer include the U.S. government,
+government subcontractors and LGIC of Korea.
+3
+Zyfer has developed a new class of encryption products for securing
+enterprise wide communications. These products provide transparent security to
+users and system administrators. Transparency results from the elimination of
+traditional key exchange and key management requirements and from our ability
+to encrypt and decrypt at high data rates.
+The space borne digital recorders serviced by Zyfer are employed in
+satellite programs for space research, earth resource and environmental
+observation and weather monitoring, as well as global surveillance and
+classified government programs.
+Sales, Marketing and Principal Customers. Zyfer conducts its selling and
+marketing activities directly from our principal facilities in Anaheim,
+California. Zyfer also sells its telecom synchronization products primarily
+through manufacturers' representatives.
+Manufacturing and Materials. Zyfer's manufacturing processes are ISO
+certified. Most of its manufacturing processes consist of final assembly and
+test. Zyfer outsources board assembly and some preliminary fabrication
+processes.
+Mariner Networks, Inc.
+Mariner Networks, Inc. has developed and manufactures a family of multi-
+service access devices that enable branch offices to cost effectively combine
+their separate voice, video and data networks onto a single wide area transport
+network. The Dexter(R) product family provides wire speed transport of most
+data traffic types. Mariner Networks' products include ATM, frame relay and
+voice subsystems for handling intranet, data, voice and video traffic.
+Sales, Marketing and Principal Customers. Mariner Networks sells its
+products through its direct sales organization and resellers in North America
+and in Europe. Mariner Networks maintains sales offices at our facilities in
+Anaheim, California and maintains a European subsidiary, Mariner Networks
+Europe Ltd., which occupies space within Odetics Europe Limited in the United
+Kingdom.
+Manufacturing and Materials. Mariner Networks' manufacturing processes are
+ISO 9000 certified and consist primarily of final assembly and test. Mariner
+Networks currently outsources circuit board assembly and some fabrication
+processes.
+ITS Products
+Iteris, Inc.
+Iteris, Inc. designs, develops, markets and implements software-based
+solutions that improve the safety and efficiency of vehicle transportation.
+Using its proprietary software and ITS industry expertise, Iteris provides
+video sensor systems and transportation management and traveler information
+systems for the ITS industry. The ITS industry is comprised of companies
+applying a variety of technologies to enable the safe and efficient movement of
+people and goods. Iteris uses its outdoor image recognition software expertise
+to develop proprietary algorithms for video sensor systems that improve vehicle
+safety and the flow of traffic. Our knowledge of the ITS industry enables
+Iteris to design and implement transportation solutions that help public
+agencies reduce traffic congestion and provide greater access to traveler
+information.
+Iteris' proprietary image recognition systems include AutoVue and Vantage.
+AutoVue is a small windshield mounted sensor that utilizes proprietary software
+to detect and warn drivers of unintended lane departures. Through new software
+development, Iteris is expanding the AutoVue platform to incorporate additional
+safety and convenience features. Vantage is a video vehicle sensing system that
+detects the presence of vehicles at signalized intersections enabling a more
+efficient allocation of green signal time.
+Iteris, Inc. designs, develops and implements software-based systems that
+integrate sensors, video surveillance, computers and advanced communications
+equipment enabling public agencies to monitor, control
+4
+and direct traffic flow, assist in the quick dispatch of emergency crews and
+distribute real-time information about traffic conditions.
+Sales, Marketing and Principal Customers. Iteris markets and sells its
+transportation management systems and services directly to government agencies
+pursuant to negotiated contracts which involve competitive bidding and specific
+qualification requirements. Sales of Iteris' systems generally involve long
+lead times and require extensive specification development, evaluation and
+price negotiations.
+Iteris sells its Vantage vehicle detection systems primarily through
+indirect sales channels comprised of independent dealers in the United States
+and Canada who sell integrated solutions and related products to the traffic
+intersection market. The independent dealers for Iteris are primarily
+responsible for sales, installation and support of Vantage systems. These
+dealers maintain an inventory of demonstration traffic products including the
+Vantage vehicle detection systems and sell directly to government agencies and
+installation contractors. These dealers often have long-term arrangements with
+the government agencies in their territory for the supply of various products
+for the construction and renovation of traffic intersections. Iteris holds
+technical training classes for its dealers and maintains a full-time staff of
+customer support technicians to provide technical assistance when needed.
+The marketing strategy for AutoVue is to establish it as the leading
+platform for in vehicle video sensing for trucks and passenger cars. AutoVue is
+sold directly by Iteris to vehicle manufacturers. Iteris currently has a direct
+sales force of two product managers, and intends to expand its sales force in
+the future to include engineers and product managers who will be responsible
+for sales and customer service to specific vehicle manufacturers. Since its
+target customer base is well known, Iteris currently does not plan to engage in
+broad-scale marketing campaigns.
+Manufacturing and Materials. Iteris designs, assembles and tests the
+components of its Vantage systems in approximately 5,000 square feet of space
+at our Anaheim facility. Production equipment consists of assembly lines and
+test apparatus for final assembly and testing of the manufactured product.
+Production volume is based upon quarterly forecasts that Iteris readjusts on a
+monthly basis to control inventory. Iteris subcontracts the manufacture of its
+AutoVue systems to two manufacturers. We anticipate these manufacturers will be
+able to produce unit volume sufficient to support sales to heavy truck
+manufacturers. Iteris intends to engage additional manufacturers with expertise
+in high volume production to produce higher volumes for light and medium trucks
+and passenger cars. Iteris does not manufacture any of the hardware used in the
+transportation management and traveler information systems that it designs and
+implements. The production facility for Iteris is ISO 9001 certified.
+Customer Support and Services
+Each of our business units is responsible for its own customer support and
+service organizations. We provide warranty service for each of our product
+lines, as well as follow-up service and support, for which we typically charge
+separately. We also offer separate software maintenance agreements to our
+customers. We view customer support services as a critical competitive factor
+as well as a revenue source.
+Backlog
+Our backlog of unfulfilled firm orders was approximately $31.0 million as of
+March 31, 2001 and approximately $27.3 million as of March 31, 2000.
+Approximately 70% of our backlog at March 31, 2000 was recognized as revenues
+in fiscal 2001, and approximately 68% of our backlog at March 31, 2001 is
+expected to be recognized as revenues in fiscal 2002. Pursuant to the customary
+terms of our agreements with government contractors and other customers,
+customers can generally cancel or reschedule orders with little or no
+penalties. Lead times for the release of purchase orders depend upon the
+scheduling and forecasting practices of our individual customers, which also
+can affect the timing of the conversion of our backlog into revenues. For these
+reasons, among others, our backlog at a particular date may not be indicative
+of our future revenues.
+5
+Product Development
+Each of our business units directs and staffs its own product development
+activities. Most of our development activities are conducted at our principal
+facilities in Anaheim, California. Mariner Networks also maintains a
+development team in La Gaude, France.
+Our business units require substantial ongoing research and development
+expenditures and other product development activities. Our company-sponsored
+research and development costs and expenses were approximately $11.2 million in
+fiscal 1999, $16.9 million in fiscal 2000 and $18.8 in fiscal 2001. We expect
+to continue to pursue significant product development programs and incur
+significant research and development expenditures in each of our business
+units.
+Competition
+Our business units generally face significant competition in each of their
+respective markets. Increased competition may result in price reductions,
+reduced gross margins and loss of market share, any of which could have a
+material adverse effect on our business, financial condition and results of
+operations.
+Broadcast's primary competitors include Sony, Harris, Encoda and Probel.
+Sony is a large, international supplier of extensive professional quality
+products, including video tape libraries, for the broadcast television market.
+Harris and Probel principally provide automation control for video libraries
+and disk recorders. Broadcast's systems compete primarily in the arena of
+facility management and enterprise wide automation. We believe that the
+capability of our systems to integrate the broadcast station business systems
+acquisition processes, storage devices and presentation devices under a
+relational data base management system represents a unique and differentiable
+capability.
+As Gyyr expands its product base from time-lapse VCRs to providing
+integrated security systems in CCTV and electronic access control, it will
+compete with a broader set of companies. Major Japanese competitors in Gyyr's
+legacy tape-based time-lapse VCR business include Panasonic, Toshiba, Sony,
+Sanyo, Mitsubishi and JVC. Gyyr also competes with large systems suppliers
+including Sensormatic, Honeywell, Pelco, Ultrak, Ademco and Vicon. In the sale
+of access control systems, Gyyr principally competes with Casi-Rusco,
+Checkpoint, Cardkey and Lenel. Gyyr generally competes based upon its strength
+in the integration of its various component products into systems that provide
+complete solutions through the use of advanced software and networking
+technologies.
+Zyfer's primary competition for network synchronization products is Datum,
+Inc. and TrueTime Inc. Zyfer anticipates that its competition for encryption
+products for secured communications systems will include Cylink Corporation,
+Rainbow Technologies, Inc. and Redcreek Communications Inc. The competition for
+integrated circuits addressing encryption applications include Broadcom
+Corporation, Chrysalis and HiFN.
+Mariner Networks' principal competition includes networking vendors Vina
+Technologies, Accelerated Networks, Marconi and Nortel Networks.
+While we believe that AutoVue is the only commercially-available lane
+departure warning system, potential competitors including Delphi Automotive
+Systems Corporation domestically, NEC Corporation and Hitachi Ltd. in Japan and
+Robert Bosch Gmbh in Europe, which are currently developing video sensor
+technologies for the vehicle industry that could be used for lane departure
+warning systems. In the market for our Vantage vehicle detection systems, we
+compete with both manufacturers of "above ground" video camera detection
+systems, such as Econolite Control Products, Inc., Trafficon, N.V. and the Peek
+Traffic Systems division of Thermo Electron Corporation, and other non-
+intrusive detection devices including microwave, infrared, ultrasonic and
+magnetic detectors, as well as manufacturers and installers of in-pavement
+inductive loop products.
+The transportation management and traveler information systems market is
+highly fragmented and is subject to evolving national and regional quality and
+safety standards. Iteris' competitors vary in number, scope
+6
+and breadth of the products and services they offer. Iteris' competitors in
+advanced transportation management and traveler information systems include
+corporations such as TRW, Inc., Transcore, Lockheed Martin Corporation, PB
+Farradyne Inc., Kimley-Horn and Associates, Inc. and National Engineering
+Technology, Inc. Iteris' competitors in transportation engineering, planning
+and design include major firms such as Parsons Brinkerhoff, Inc. and Parsons
+Transportation Group Inc., as well as many regional engineering firms.
+In general, the markets for the products and services offered by our
+businesses are highly competitive and are characterized by rapidly changing
+technology and evolving standards. Many of our current and prospective
+competitors have longer operating histories, greater name recognition, access
+to larger customer bases and significantly greater financial, technical,
+manufacturing, distribution and marketing resources than us. As a result, they
+may be able to adapt more quickly to new or emerging standards or technologies
+or to devote greater resources to the promotion and sale of their products. It
+is also possible that new competitors or alliances among competitors could
+emerge and rapidly acquire significant market share. We believe that our
+ability to compete effectively in our target markets depends on a number of
+factors, including the success and timing of our new product development, the
+compatibility of our products with a broad range of computing systems, product
+quality and performance, reliability, functionality, price, and service and
+technical support. Our failure to provide services and develop and market
+products that compete successfully with those of other suppliers and
+consultants in our target markets would have a material adverse effect on our
+business, financial condition and results of operations.
+Intellectual Property and Proprietary Rights
+Our ability to compete effectively depends in part on our ability to develop
+and maintain the proprietary aspects of our technology. Our policy is to obtain
+appropriate proprietary rights protection for any potentially significant new
+technology acquired or developed each of our business units. We currently hold
+a number of United States and foreign patents and trademarks, which will expire
+at various dates commencing in 2004. We also have pending a number of United
+States and foreign patent applications relating to certain of our products;
+however, we cannot be certain that any patents will be granted pursuant to
+these applications.
+In addition to patent laws, we rely on copyright and trade secret laws to
+protect our proprietary rights. We attempt to protect our trade secrets and
+other proprietary information through agreements with customers and suppliers,
+proprietary information agreements with our employees and consultants, and
+other similar measures. We cannot be certain that we will be successful in
+protecting our proprietary rights. While we believe our patents, patent
+applications, software and other proprietary know-how have value, changing
+technology makes our future success dependent principally upon our employees'
+technical competence and creative skills for continuing innovation.
+Litigation has been necessary in the past and may be necessary in the future
+to enforce our proprietary rights, to determine the validity and scope of the
+proprietary rights of others, or to defend us against claims of infringement or
+invalidity by others. An adverse outcome in such litigation or similar
+proceedings could subject us to significant liabilities to third parties,
+require disputed rights to be licensed from others or require us to cease
+marketing or using certain products, any of which could have a material adverse
+effect on our business, financial condition and results of operations. In
+addition, the cost of addressing any intellectual property litigation claim,
+both in legal fees and expenses, as well as from the diversion of management's
+resources, regardless of whether the claim is valid, could be significant and
+could have a material adverse effect on our business, financial condition and
+results of operations.
+Employees
+We refer to our employees as associates. As of June 20, 2001, we employed
+442 associates, including 72 associates in general management, administration
+and finance; 65 associates in sales and marketing; 170 associates in product
+development; 105 associates in operations, manufacturing and quality; and
+30 associates in customer service. None of our associates are represented by a
+labor union and we have not experienced a work stoppage.
+7
+We provide centralized support for human resources management for each of
+our business units and subsidiaries. These services include recruiting,
+administration and outplacement.
+Government Regulation
+Our manufacturing operations are subject to various federal, state and local
+laws, including those restricting the discharge of materials into the
+environment. We are not involved in any pending or threatened proceedings which
+would require curtailment of our operations because of such regulations. We
+continue to expend funds in connection with our compliance with applicable
+environmental regulations. These expenditures have not, however, been
+significant in the past, and we do not expect any significant expenditures in
+the near future.
+From time to time, a portion of our work relating to network synchronization
+systems may constitute classified United States government information or may
+be used in classified programs of the United States Government. For this
+purpose, we possess certain relevant security clearances. Our affected
+facilities and operations are also subject to security regulations of the
+United States Government. We believe we are currently in full compliance with
+these regulations.
+8
+RISK FACTORS
+Our business is subject to a number of risks, some of which are discussed
+below. Other risks are presented elsewhere in this report. You should consider
+the following risks carefully in addition to the other information contained in
+this report before purchasing the shares of our common stock. If any of the
+following risks actually occur, they could seriously harm our business,
+financial condition or results of operations. In such case, the trading price
+of our common stock could decline, and you may lose all or part of your
+investment.
+We Have Experienced Substantial Losses and Expect Future Losses. We
+experienced significant operating losses of $49.8 million for the year ended
+March 31, 2001, $38.7 million for the year ended March 31, 2000 and $18.3
+million for the year ended March 31, 1999. In January 2001, we announced the
+reorganization of our business in order to reduce our operating expenses and
+negative cash flow, which included the downsizing of our operations in Gyyr and
+Broadcast, and a 25% reduction in our total work force. We cannot assure you
+that this reorganization will improve our financial performance, or that we
+will be able to achieve profitability on a quarterly or annual basis in the
+future. Most of our expenses are fixed in advance, and we generally are unable
+to reduce our expenses significantly in the short-term to compensate for any
+unexpected delay or decrease in anticipated revenues. As a result, we may
+continue to experience losses, which could cause the market price of our common
+stock to decline.
+We Will Need to Raise Additional Capital in the Future and May Not Be Able
+to Secure Adequate Funds on Terms Acceptable to Us, or at All. Our line of
+credit facility expired on December 31, 2000. While we have received an
+extension on this facility until July 31, 2001, we will need to obtain a new
+line of credit from another lender in the near future. Substantially all of our
+assets have been pledged to our existing lender to secure the outstanding
+indebtedness under this facility ($13.5 million at March 31, 2001). We cannot
+assure you that we will be able to obtain a new line of credit on a timely
+basis, on acceptable terms, or at all. Even if we are able to secure a new line
+of credit, we anticipate that we will need to raise additional capital in the
+near future, either through additional bank borrowings, the monetization of
+certain real property, the divestiture of business units or select assets, or
+other debt or equity financings. These conditions, together with our recurring
+losses, raise substantial doubt about our ability to continue as a going
+concern.
+Our capital requirements will depend on many factors, including:
+. our ability to control costs;
+. increased research and development funding, and required investments in
+our business units;
+. our ability to generate operating income;
+. market acceptance of our products;
+. technological advancements and our competitors' response to our
+products;
+. capital improvements to new and existing facilities;
+. increased sales and marketing expenses;
+. potential acquisitions of businesses and product lines; and
+. additional working capital needs.
+If our capital requirements are materially different from those currently
+planned, we may need additional capital sooner than anticipated. If additional
+funds are raised through the issuance of equity securities, the percentage
+ownership of our stockholders will be reduced and such securities may have
+rights, preferences and privileges senior to our common stock. Additional
+financing may not be available on favorable terms or at all. If adequate funds
+are not available or are not available on acceptable terms, we may be unable to
+develop or enhance our products, expand our sales and marketing programs, take
+advantage of future opportunities or respond to competitive pressures.
+9
+Our Quarterly Operating Results Fluctuate as a Result of Many Factors. Our
+quarterly revenues and operating results have fluctuated and are likely to
+continue to vary from quarter to quarter due to a number of factors, many of
+which are not within our control. Factors that could affect our revenues
+include, among others, the following:
+. our significant investment in research and development for our
+subsidiaries and business units;
+. our ability to control costs;
+. our ability to develop, introduce, market and gain market acceptance of
+new products applications and product enhancements in a timely manner;
+. the size, timing, rescheduling or cancellation of significant customer
+orders;
+. the introduction of new products by competitors;
+. the availability of components used in the manufacture of our products;
+. changes in our pricing policies and the pricing policies by our
+suppliers and competitors, pricing concessions on volume sales, as well
+as increased price competition in general;
+. the long lead times associated with government contracts or required by
+vehicle manufacturers;
+. our success in expanding and implementing our sales and marketing
+programs;
+. the effects of technological changes in our target markets;
+. our relatively small level of backlog at any given time;
+. the mix of sales among our business units;
+. deferrals of customer orders in anticipation of new products,
+applications or product enhancements;
+. the risks inherent in our acquisitions of technologies and businesses;
+. risks and uncertainties associated with our international business;
+. currency fluctuations and our ability to get currency out of certain
+foreign countries; and
+. general economic and market conditions.
+In addition, our sales in any quarter may consist of a relatively small
+number of large customer orders. As a result, the timing of a small number of
+orders may impact our quarter to quarter results. The loss of or a substantial
+reduction in orders from any significant customer could seriously harm our
+business, financial condition and results of operations.
+Due to all of the factors listed above and other risks discussed in this
+report, our future operating results could be below the expectations of
+securities analysts or investors. If that happens, the trading price of our
+common stock could decline. As a result of these quarterly variations, you
+should not rely on quarter-to-quarter comparisons of our operating results as
+an indication of our future performance.
+Our Operating Strategy for Developing Companies is Expensive and May Not Be
+Successful. Our business strategy entails intensive business development
+activities, which are expensive and highly risky. The goal of this strategy is
+to develop companies that can be spun-off to our stockholders. This strategy
+has in the past required us to make significant investments in our business
+units, both for research and development, and also to develop a separate
+infrastructure for certain of our business units, sufficient to allow the unit
+to function as an independent public company. We expect to continue to invest
+in the development of certain of our business units with the goal of obtaining
+additional capital to support further investment and eventually completing
+additional public offerings. We may not recognize the benefits of this
+investment for a significant
+10
+period of time, if at all. Our ability to complete private financings or an
+initial public offering of any of our business units and/or spin-off our
+interest to our stockholders will depend upon many factors, including:
+. the overall performance and results of operations of the particular
+business unit;
+. the potential market for our business unit;
+. our ability to assemble and retain a broad, qualified management team
+for the business unit;
+. our financial position and cash requirements;
+. the business unit's customer base and product line;
+. the current tax treatment of spin-off transactions and our ability to
+obtain favorable determination letters from the Internal Revenue
+Service; and
+. general economic and market conditions, including the receptiveness of
+the stock markets to initial public offerings.
+We may not be able to complete a successful private or public offering or
+spin-off of any of our business units in the near future, or at all. During
+fiscal 2001, we attempted to complete the initial public offering of Iteris. We
+withdrew the offering due to adverse market conditions. Even if we do complete
+additional public offerings, we may decide not to spin-off a particular
+business unit, or to delay the spin-off until a later date.
+We Must Keep Pace with Rapid Technological Change to Remain Competitive. Our
+target markets are in general characterized by the following factors:
+. rapid technological advances;
+. downward price pressure in the marketplace as technologies mature;
+. changes in customer requirements;
+. frequent new product introductions and enhancements; and
+. evolving industry standards and changes in the regulatory environment.
+Our future success will depend upon our ability to anticipate and adapt to
+changes in technology and industry standards, and to effectively develop,
+introduce, market and gain broad acceptance of new products and product
+enhancements incorporating the latest technological advancements.
+We believe that we must continue to make substantial investments to support
+ongoing research and development in order to remain competitive. We need to
+continue to develop and introduce new products that incorporate the latest
+technological advancements in hardware, storage media, operating system
+software and applications software in response to evolving customer
+requirements. Our business and results of operations could be adversely
+affected if we do not anticipate or respond adequately to technological
+developments or changing customer requirements. We cannot assure you that any
+such investments in research and development will lead to any corresponding
+increase in revenue.
+Our Future Success Depends on the Successful Development and Market
+Acceptance of New Products. We believe our revenue growth and future operating
+results will depend on our ability to complete development of new products and
+enhancements, introduce these products in a timely, cost-effective manner,
+achieve broad market acceptance of these products and enhancements, and reduce
+our product costs. We may not be able to introduce any new products or any
+enhancements to our existing products on a timely basis, or at all. In
+addition, the introduction of any new products could adversely affect the sales
+of our certain of our existing products.
+Our future success will also depend in part on the success of several
+recently introduced products including DVMS, our family of digital time-lapse
+recorders; AutoVue, our lane departure warning system; and Dexter, our multi-
+service access device.
+11
+Market acceptance of our new products depends upon many factors, including
+our ability to accurately predict market requirements and evolving industry
+standards, our ability to resolve technical challenges in a timely and cost-
+effective manner and achieve manufacturing efficiencies, the perceived
+advantages of our new products over traditional products and the marketing
+capabilities of our independent distributors and strategic partners. Our
+business and results of operations could be seriously harmed by any significant
+delays in our new product development. We have experienced delays in the past
+in the introduction of new products, particularly with our Roswell system,
+which we recently discontinued. Certain of our new products could contain
+undetected design faults and software errors or "bugs" when first released by
+us, despite our testing. We may not discover these faults or errors until after
+a product has been installed and used by our customers. Any faults or errors in
+our existing products or in any new products may cause delays in product
+introduction and shipments, require design modifications or harm customer
+relationships, any of which could adversely affect our business and competitive
+position.
+We currently outsource the manufacture of our AutoVue product line to a
+single manufacturer. This manufacturer may not be able to produce sufficient
+quantities of this product in a timely manner or at a reasonable cost, which
+could materially and adversely affect our ability to launch or gain market
+acceptance of AutoVue.
+We Have Significant International Sales and Are Subject to Risks Associated
+with Operating in International Markets. International product sales
+represented approximately 20% of our total net sales and contract revenues for
+the fiscal year ended March 31, 2001, approximately 19% for the fiscal year
+ended March 31, 2000 and approximately 27% for the fiscal year ended March 31,
+1999. International business operations are subject to inherent risks,
+including, among others:
+. unexpected changes in regulatory requirements, tariffs and other trade
+barriers or restrictions;
+. longer accounts receivable payment cycles;
+. difficulties in managing and staffing international operations;
+. potentially adverse tax consequences;
+. the burdens of compliance with a wide variety of foreign laws;
+. import and export license requirements and restrictions of the United
+States and each other country in which we operate;
+. exposure to different legal standards and reduced protection for
+intellectual property rights in some countries;
+. currency fluctuations and restrictions; and
+. political, social and economic instability.
+We believe that international sales will continue to represent a significant
+portion of our revenues, and that continued growth and profitability may
+require further expansion of our international operations. Many of our
+international sales are currently denominated in U.S. dollars. As a result, an
+increase in the relative value of the dollar could make our products more
+expensive and potentially less price competitive in international markets. We
+do not engage in any transactions as a hedge against risks of loss due to
+foreign currency fluctuations.
+Any of these factors may adversely effect our future international sales
+and, consequently, on our business and operating results. Furthermore, as we
+increase our international sales, our total revenues may also be affected to a
+greater extent by seasonal fluctuations resulting from lower sales that
+typically occur during the summer months in Europe and other parts of the
+world.
+We Need to Manage Growth and the Integration of Our Acquisitions. Over the
+past few years, we have expanded our operations and made several substantial
+acquisitions of diverse businesses, including Intelligent
+12
+Controls, Inc., International Media Integration Services, Ltd., Meyer Mohaddes
+Associates, Inc., Viggen Corporation, certain assets of the Transportation
+Systems business of Rockwell International, and the Security Products Division
+of Digital Systems Processing, Inc. A key element of our business strategy
+involves expansion through the acquisition of complementary businesses,
+products and technologies. Acquisitions may require significant capital
+infusions and, in general, acquisitions also involve a number of special risks,
+including:
+. potential disruption of our ongoing business and the diversion of our
+resources and management's attention;
+. the failure to retain or integrate key acquired personnel;
+. the challenge of assimilating diverse business cultures, and the
+difficulties in integrating the operations, technologies and information
+system of the acquired companies;
+. increased costs to improve managerial, operational, financial and
+administrative systems and to eliminate duplicative services;
+. the incurrence of unforeseen obligations or liabilities;
+. potential impairment of relationships with employees or customers as a
+result of changes in management; and
+. increased interest expense and amortization of acquired intangible
+assets.
+Acquisitions may also materially and adversely affect our operating results
+due to large write-offs, contingent liabilities, substantial depreciation,
+deferred compensation charges or goodwill amortization, or other adverse tax or
+audit consequences.
+Our competitors are also soliciting potential acquisition candidates, which
+could both increase the price of any acquisition targets and decrease the
+number of attractive companies available for acquisition. We cannot assure you
+that we will be able to consummate any additional acquisitions, successfully
+integrate any acquisitions or realize the benefits anticipated from any
+acquisition.
+Acquisitions, combined with the expansion of our business units and recent
+growth has placed and is expected to continue to place a significant strain on
+our resources. To accommodate this growth, we anticipate that we will be
+required to implement a variety of new and upgraded operational and financial
+systems, procedures and controls, including the improvement of our accounting
+and other internal management systems. All of these updates will require
+substantial additional expense as well as management effort. Our failure to
+manage growth and integrate our acquisitions successfully could adversely
+affect our business, financial condition and results of operations.
+We Depend on Government Contracts and Subcontracts and Face Additional Risks
+Related to Fixed Price Contracts. A significant portion of the sales by Iteris
+and a portion of our sales by Zyfer were derived from contracts with
+governmental agencies, either as a general contractor, subcontractor or
+supplier. Government contracts represented approximately 25% and 26% of our
+total net sales and contract revenues for the years ended March 31, 2000 and
+2001, respectively. We anticipate that revenue from government contracts will
+continue to increase in the near future. Government business is, in general,
+subject to special risks and challenges, including:
+. long purchase cycles;
+. competitive bidding and qualification requirements;
+. performance bond requirements;
+. delays in funding, budgetary constraints and cut-backs; and
+. milestone requirements and liquidated damage provisions for failure to
+meet contract milestones.
+13
+In addition, a large number of our government contracts are fixed price
+contracts. As a result, we may not be able to recover for any cost overruns.
+These fixed price contracts require us to estimate the total project cost based
+on preliminary projections of the project's requirements. The financial
+viability of any given project depends in large part on our ability to estimate
+these costs accurately and complete the project on a timely basis. In the event
+our costs on these projects exceed the fixed contractual amount, we will be
+required to bear the excess costs. These additional costs adversely affect our
+financial condition and results of operations. Moreover, certain of our
+government contracts are subject to termination or renegotiation at the
+convenience of the government, which could result in a large decline in our net
+sales in any given quarter. Our inability to address any of the foregoing
+concerns or the loss or renegotiation of any material government contract could
+seriously harm our business, financial condition and results of operations.
+The Markets in Which We Operate Are Highly Competitive and Have Many More
+Established Competitors. We compete with numerous other companies in our target
+markets and we expect such competition to increase due to technological
+advancements, industry consolidations and reduced barriers to entry. Increased
+competition is likely to result in price reductions, reduced gross margins and
+loss of market share, any of which could seriously harm our business, financial
+condition and results of operations. Many of our competitors have far greater
+name recognition and greater financial, technological, marketing and customer
+service resources than we do. This may allow them to respond more quickly to
+new or emerging technologies and changes in customer requirements. It may also
+allow them to devote greater resources to the development, promotion, sale and
+support of their products than we can. Recent consolidations of end users,
+distributors and manufacturers in our target markets have exacerbated this
+problem. As a result of the foregoing factors, we may not be able to compete
+effectively in our target markets and competitive pressures could adversely
+affect our business, financial condition and results of operations.
+We Cannot Be Certain of Our Ability to Attract and Retain Key Personnel and
+We Do Not Have Employment Agreements with Any Key Personnel. Due to the
+specialized nature of our business, we are highly dependent on the continued
+service of our executive officers and other key management, engineering and
+technical personnel, particularly Joel Slutzky, our Chief Executive Officer and
+Chairman of the Board, and Gregory A. Miner, our Chief Operating Officer and
+Chief Financial Officer. We do not have any employment contracts with any of
+our officers or key employees. The loss of any of these persons would seriously
+harm our development and marketing efforts, and would adversely affect our
+business. Our success will also depend in large part upon our ability to
+continue to attract, retain and motivate qualified engineering and other highly
+skilled technical personnel. Competition for employees, particularly
+development engineers, is intense. We may not be able to continue to attract
+and retain sufficient numbers of such highly skilled employees. Our inability
+to attract and retain additional key employees or the loss of one or more of
+our current key employees could adversely affect upon our business, financial
+condition and results of operations.
+We May Not be Able to Adequately Protect or Enforce Our Intellectual
+Property Rights. If we are not able to adequately protect or enforce the
+proprietary aspects of our technology, competitors could be able to access our
+proprietary technology and our business, financial condition and results of
+operations will likely be seriously harmed. We currently attempt to protect our
+technology through a combination of patent, copyright, trademark and trade
+secret laws, employee and third party nondisclosure agreements and similar
+means. Despite our efforts, other parties may attempt to disclose, obtain or
+use our technologies or solutions. Our competitors may also be able to
+independently develop products that are substantially equivalent or superior to
+our products or design around our patents. In addition, the laws of some
+foreign countries do not protect our proprietary rights as fully as do the laws
+of the United States. As a result, we may not be able to protect our
+proprietary rights adequately in the United States or abroad.
+From time to time, we have received notices that claim we have infringed
+upon the intellectual property of others. Even if these claims are not valid,
+they could subject us to significant costs. We have engaged in litigation in
+the past, and litigation may be necessary in the future to enforce our
+intellectual property rights or to determine the validity and scope of the
+proprietary rights of others. Litigation may also be necessary to defend
+against claims of infringement or invalidity by others. An adverse outcome in
+litigation or any similar
+14
+proceedings could subject us to significant liabilities to third parties,
+require us to license disputed rights from others or require us to cease
+marketing or using certain products or technologies. We may not be able to
+obtain any licenses on terms acceptable to us, or at all. We also may have to
+indemnify certain customers or strategic partners if it is determined that we
+have infringed upon or misappropriated another party's intellectual property.
+Any of these results could adversely affect on our business, financial
+condition and results of operations. In addition, the cost of addressing any
+intellectual property litigation claim, both in legal fees and expenses, and
+the diversion of management resources, regardless of whether the claim is
+valid, could be significant and could seriously harm our business, financial
+condition and results of operations.
+The Trading Price of Our Common Stock Is Volatile. The trading price of our
+common stock has been subject to wide fluctuations in the past. Since January
+2000, our Class A common stock has traded at prices as low as $1.88 per share
+and as high as $29.44 per share. We may not be able to increase or sustain the
+current market price of our common stock in the future. As such, you may not be
+able to resell your shares of common stock at or above the price you paid for
+them. The market price of our common stock could continue to fluctuate in the
+future in response to various factors, including, but not limited to:
+. quarterly variations in operating results;
+. our ability to control costs and improve cash flow;
+. shortages announced by suppliers;
+. announcements of technological innovations or new products by our
+competitors, customers or us;
+. acquisitions or businesses, products or technologies;
+. changes in pending litigation or new litigation;
+. changes in investor perceptions;
+. our ability to spin-off any business unit;
+. applications or product enhancements by us or by our competitors; and
+. changes in earnings estimates or investment recommendations by
+securities analysts.
+The stock market in general has recently experienced volatility, which has
+particularly affected the market prices of equity securities of many high
+technology companies. This volatility has often been unrelated to the operating
+performance of these companies. These broad market fluctuations may adversely
+affect the market price of our common stock. In the past, companies that have
+experienced volatilities in the market price of their securities have been the
+subject of securities class action litigation. If we were to become the subject
+of a class action lawsuit, it could result in substantial losses and divert
+management's attention and resources from other matters.
+We Are Controlled by Certain of Our Officers and Directors. As of June 21,
+2001, our officers and directors beneficially owned approximately 28% of the
+total combined voting power of the outstanding shares of our Class A common
+stock and Class B common stock. As a result of their stock ownership, our
+management will be able to significantly influence the election of our
+directors and the outcome of corporate actions requiring stockholder approval,
+such as mergers and acquisitions, regardless of how our other stockholders may
+vote. This concentration of voting control may have a significant effect in
+delaying, deferring or preventing a change in our management or change in
+control and may adversely affect the voting or other rights of other holders of
+common stock.
+Our Stock Structure and Certain Anti-Takeover Provisions May Affect the
+Price of Our Common Stock. Certain provisions of our certificate of
+incorporation and our stockholder rights plan could make it difficult for a
+third party to acquire us, even though an acquisition might be beneficial to
+our stockholders. These provisions could limit the price that investors might
+be willing to pay in the future for shares of our common stock. Our Class A
+common stock entitles the holder to one-tenth of one vote per share and our
+15
+Class B common stock entitles the holder to one vote per share. The disparity
+in the voting rights between our common stock, as well as our insiders'
+significant ownership of the Class B common stock, could discourage a proxy
+contest or make it more difficult for a third party to effect a change in our
+management and control. In addition, our Board of Directors is authorized to
+issue, without stockholder approval, up to 2,000,000 shares of preferred stock
+with voting, conversion and other rights and preferences superior to those of
+our common stock, as well as additional shares of Class B common stock. Our
+future issuance of preferred stock or Class B common stock could be used to
+discourage an unsolicited acquisition proposal.
+In March 1998, we adopted a stockholder rights plan and declared a dividend
+of preferred stock purchase rights to our stockholders. In the event a third
+party acquires more than 15% of the outstanding voting control of our company
+or 15% of our outstanding common stock, the holders of these rights will be
+able to purchase the junior participating preferred stock at a substantial
+discount off of the then current market price. The exercise of these rights and
+purchase of a significant amount of stock at below market prices could cause
+substantial dilution to a particular acquiror and discourage the acquiror from
+pursuing our company. The mere existence of a stockholder rights plan often
+delays or makes a merger, tender offer or proxy contest more difficult.
+We Do Not Pay Cash Dividends. We have never paid cash dividends on our
+common stock and do not anticipate paying any cash dividends on either class of
+our common stock in the foreseeable future.
+We May Be Subject to Additional Risks. The risks and uncertainties described
+above are not the only ones facing our company. Additional risks and
+uncertainties not presently known to us or that we currently deem immaterial
+may also adversely affect our business operations.
\ No newline at end of file
diff --git a/raw/filings/0000350868/2000/0000931763-01-501040/item13.txt b/raw/filings/0000350868/2000/0000931763-01-501040/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..dfd3a4671c1027787ba16fb40c9a1f0d883ded5a
--- /dev/null
+++ b/raw/filings/0000350868/2000/0000931763-01-501040/item13.txt
@@ -0,0 +1,4 @@
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
+The information under the heading "Certain Transactions," appearing in our
+proxy statement, is incorporated herein by reference.
+26
\ No newline at end of file
diff --git a/raw/filings/0000350868/2000/0000931763-01-501040/item9a.txt b/raw/filings/0000350868/2000/0000931763-01-501040/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000350868/2000/0000931763-01-501040/rp_note.txt b/raw/filings/0000350868/2000/0000931763-01-501040/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..818c98289a84f99fe276587c1703b7b8e9c3496f
--- /dev/null
+++ b/raw/filings/0000350868/2000/0000931763-01-501040/rp_note.txt
@@ -0,0 +1,6 @@
+5. Related Party Transaction
+In July 1999, the Company sold an option to an investment company controlled
+by certain officers and shareholders of the Company, for an aggregate purchase
+price of $5.0 million to purchase certain real property of Odetics. In August
+2000 the Company repurchased the option for $5.6 million which represented the
+original purchase price plus accrued interest.
\ No newline at end of file
diff --git a/raw/filings/0000350868/2000/0000931763-01-501040/rpt_disclosure.txt b/raw/filings/0000350868/2000/0000931763-01-501040/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000350868/2001/0001017062-02-001321/filing.txt b/raw/filings/0000350868/2001/0001017062-02-001321/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..fbb442c540a677a8069a512e4c0f59a41ae0a443
--- /dev/null
+++ b/raw/filings/0000350868/2001/0001017062-02-001321/filing.txt
@@ -0,0 +1,3180 @@
+10-K
+1
+d10k.txt
+ODETICS, INC. FORM 10-K
+================================================================================
+UNITED STATES
+SECURITIES AND EXCHANGE COMMISSION
+Washington, D.C. 20549
+FORM 10-K
+__________________
+FOR ANNUAL AND TRANSITION REPORTS PURSUANT TO SECTIONS 13 OR 15(d)
+OF THE SECURITIES EXCHANGE ACT OF 1934
+(Mark One)
+[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
+ACT OF 1934
+For the fiscal year ended March 31, 2002
+OR
+[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
+EXCHANGE ACT OF 1934
+For the transition period from ________ to ________
+Commission file number 000-10605
+__________________
+ODETICS, INC.
+(Exact Name of Registrant as Specified in Its Charter)
+Delaware 95-2588496
+(State or Other Jurisdiction (I.R.S. Employer
+of Incorporation or Organization) Identification No.)
+1515 South Manchester Avenue, Anaheim, California 92802
+(Address of Principal Executive Offices) (Zip Code)
+Registrant's Telephone Number, Including Area Code: (714) 774-5000
+__________________
+Securities registered pursuant to Section 12(b) of the Act: None
+Securities registered pursuant to Section 12(g) of the Act:
+Class A common stock, $.10 par value
+Class B common stock, $.10 par value
+(Title of Class)
+__________________
+Indicate by check mark whether the registrant: (1) has filed all reports
+required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
+1934 during the preceding 12 months (or for such shorter period that the
+registrant was required to file such reports), and (2) has been subject to such
+filing requirements for the past 90 days. Yes [X] No [_]
+Indicate by a check mark if disclosure of delinquent filers pursuant to
+Item 405 of Regulation S-K is not contained herein, and will not be contained,
+to the best of registrant's knowledge, in definitive proxy or information
+statements incorporated by reference in Part III of this Form 10-K or any
+amendment to this Form 10-K [X]
+Based on the closing sale price on Nasdaq SmallCap Market on June 27, 2002,
+the aggregate market value of the voting stock held by nonaffiliates of the
+registrant was $20,574,481. For the purposes of this calculation, shares owned
+by officers, directors and 10% stockholders known to the registrant have been
+deemed to be owned by affiliates. This determination of affiliate status is not
+necessarily a conclusive determination for other purposes.
+Odetics has two classes of common stock outstanding, the Class A common
+stock and the Class B common stock. The rights, preferences and privileges of
+each class of common stock are identical in all respects, except for voting
+rights. Each share of Class A common stock entitles its holder to one-tenth of
+one vote per share and each share of Class B common stock entitles its holder to
+one vote per share. As of June 27, 2002, there were 11,580,914 shares of Class A
+common stock and 1,035,841 shares of Class B common stock outstanding. Unless
+otherwise indicated, all references to common stock collectively refer to the
+Class A common stock and the Class B common stock.
+DOCUMENTS INCORPORATED BY REFERENCE
+Part III incorporates by reference certain information from the
+registrant's proxy statement for the Annual Meeting of Stockholders to be held
+September 13, 2002.
+================================================================================
+ODETICS, INC.
+FORM 10-K ANNUAL REPORT
+TABLE OF CONTENTS
+PART I Page
+----
+ITEM 1. BUSINESS ............................................................ 1
+ITEM 2. PROPERTIES .......................................................... 14
+ITEM 3. LEGAL PROCEEDINGS ................................................... 15
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ................. 15
+PART II
+ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
+STOCKHOLDER MATTERS ................................................. 16
+ITEM 6. SELECTED FINANCIAL DATA ............................................. 17
+ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
+RESULTS OF OPERATIONS ............................................... 18
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK ........... 26
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ......................... 26
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
+AND FINANCIAL DISCLOSURE ............................................ 26
+PART III
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT .................. 27
+ITEM 11. EXECUTIVE COMPENSATION .............................................. 27
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
+MANAGEMENT .......................................................... 27
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ...................... 27
+PART IV
+ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
+FORM 8-K ............................................................ 27
+In this report, "Odetics," the "Company," the "Registrant," "we," "us" and
+"our" collectively refers to Odetics, Inc. and its wholly-owned subsidiaries.
+Note: This report contains forward-looking statements which are based on
+our current expectations, estimates and projections about our business and our
+industry, and reflect management's beliefs and certain assumptions made by us
+based upon information available to us as of the date of this report. When used
+in this Annual Report on Form 10-K and the information incorporated herein by
+reference, the words "expect(s)," "feel(s)," "believe(s)," "will," "may,"
+"anticipate(s)," and similar expressions are intended to identify
+forward-looking statements. These forward-looking statements include but are not
+limited to statements regarding our anticipated revenue, expenses, capital
+needs, backlog and manufacturing capabilities and the status of our facilities.
+These statements are not guarantees of future performance and are subject to
+certain risks and uncertainties which could cause actual results to differ
+materially from those projected. You should not place undue reliance on these
+forward-looking statements that speak only as of the date hereof. We undertake
+no obligation to republish revised forward-looking statements to reflect events
+or circumstances after the date hereof or to reflect the occurrence of
+unanticipated events. We encourage you to carefully review and consider the
+various disclosures made by us which describe certain factors which could affect
+our business, including the risk factors set forth at the end of Part I, Item 1
+of this report and in Part II, Item 7. "Management's Discussion and Analysis of
+Financial Condition and Results of Operations."
+PART I
+ITEM 1. BUSINESS
+General
+Odetics, Inc. provides products, systems, and services that control and
+manage the use of public roadways, secure access to public and private
+facilities, and secure the delivery of digital communications. Our company was
+founded in 1969 to supply digital recorders for use in the United States space
+program. We pioneered new designs and standards for digital magnetic tape
+recorders offering high reliability and enhanced performance in the adverse
+environment attendant to space flight. In the 1970s, we broadened our
+information automation product line to include time-lapse videocassette
+recorders for commercial security and surveillance applications, and entered the
+business of manufacturing telecom network synchronization products. Through our
+Gyyr Incorporated subsidiary, we became a leading supplier of time-lapse
+videotape cassette recorders, and we pioneered new products incorporating
+digital video technologies and related CCTV products used in security and
+surveillance systems. In April 2001, we sold Gyyr's Vortex Dome and Quarterback
+Controller product lines. Then in September 2001, we sold the assets of our CCTV
+product line, and changed the name of our Gyyr subsidiary to MAXxess Systems
+Inc. to continue to pursue the security market with electronic access control
+products and systems.
+Beginning in the late 1970s, we developed and manufactured telecom
+synchronization products in our Communications division. We incorporated our
+Communications division in fiscal 1999 as our wholly-owned subsidiary, Zyfer,
+Inc., as part of our business expansion to develop products focused on the
+security aspects of data traffic over ground and satellite links, and network
+communications.
+Leveraging our expertise in video image processing, we entered into the
+intelligent transportation system ("ITS") business with the introduction of a
+video-based vehicle detection system in 1993. In June 1997, we acquired certain
+assets comprising the Transportation Systems business from Rockwell
+International, creating our ITS division, which expanded our offerings to
+include advanced traffic management systems and advanced traveler information
+systems. We incorporated our ITS division in 1998 as Odetics ITS, Inc. In
+October 1998, we broadened our systems offerings by acquiring Meyer, Mohaddes
+Associates, Inc. In January 2000, we reincorporated Odetics ITS in Delaware and
+changed its name to Iteris, Inc. Odetics currently owns 78.2% of the outstanding
+common stock of Iteris or 62.7% as calculated for the preferred stock conversion
+equivalent. Meyer, Mohaddes Associates, Inc. currently operates as a
+wholly-owned subsidiary of Iteris, Inc.
+In the early 1980s, we developed the technical expertise to apply
+automation to new commercial applications and established our Odetics Broadcast
+division. We incorporated our Odetics Broadcast division in 1999 as Broadcast,
+Inc. Broadcast is a supplier of content management and delivery solutions for
+the television, cable and satellite industries. The success of our video tape
+libraries led us to pursue new applications for information automation
+technologies. In 1991, we introduced an automated tape handling subsystem for
+integration into tape libraries designed for midrange computers and
+client/server networks. In January 1993, we formed a separate subsidiary, ATL
+Products, Inc., to pursue the market for automated tape libraries. In March
+1997, ATL completed an initial public offering of 1,650,000 shares of its Class
+A common stock. We distributed our remaining 82.9% interest in ATL to our
+stockholders in a tax-free distribution in October 1997.
+1
+Odetics has a unique mix of competencies in outdoor image processing,
+high-speed security processing, precision timing and synchronization, and data
+management. We have a unique identity within each of our vertical markets that
+we address, and our business is organizationally structured so that our
+management teams and technical competencies are in alignment with each area of
+market focus. Our business units share a common overhead structure for
+facilities, human resources, benefits and certain accounting, finance and
+management services.
+We currently define our business segments as video products, telecom
+products and ITS. Our video products segment includes our Broadcast subsidiary
+and our MAXxess subsidiary. Our telecom products segment consists of our Zyfer
+subsidiary. Our ITS segment consists of our Iteris subsidiary. For more
+information concerning our business segments, please see Note [14] of Notes to
+Consolidated Financial Statements.
+Video Products
+Broadcast, Inc.
+Broadcast is a supplier of content management and delivery solutions for
+the television, cable and satellite industries. Broadcast's systems automate the
+storage and scheduling of commercials, news stories and other television
+programming recorded on video server storage systems and videotape. We believe
+that enhanced operational efficiencies are a principal factor underlying the
+automation of broadcast television stations and satellite uplink operations as
+the industry transitions to digital television. The Broadcast product offering
+is based on proprietary software solutions for broadband video content
+management and delivery to serve broadcast and cable operations. The AIRO(TM)
+suite of products is Broadcast's content management and delivery solution that
+is designed to automate the on-air operations of television and cable
+broadcasters.
+Sales, Marketing and Principal Customers. Broadcast sells directly to
+broadcast television stations, satellite uplink operations, and other broadcast
+television and cable television system operators. The sales and marketing
+management for Broadcast is located at our principal facilities in Anaheim,
+California. Broadcast maintains a dedicated field sales force of four persons
+operating in four sales regions in North America, and two sales managers for
+Latin America and Europe. Broadcast also utilizes additional independent
+representative organizations to promote its products in various other foreign
+markets. During the year ended March 31, 2002, Broadcast implemented indirect
+sales channels consisting of system integrators, value added resellers and
+system distributors.
+The customers of Broadcast include major television networks such as Fox,
+Nickelodeon, CNBC, Televisa, Measat Broadcast Network Systems, NBC, the PBS
+Network, Group W Satellite Communications, Asia Broadcast Centre, Univision and
+over 250 independent and network-affiliated television stations. Broadcast
+currently has systems installed in over 40 countries.
+Manufacturing and Materials. Within our Anaheim facilities, Broadcast
+maintains a dedicated manufacturing operation as well as infrastructure to
+support production and inventory control, purchasing, quality assurance and
+manufacturing. Our AIRO products are serviced primarily in a facility located in
+Austin, Texas.
+Broadcast purchases video servers from Grass Valley Group, Leitch and
+Pinnacle Systems and purchases video switching, conversion and monitoring
+equipment from Grass Valley Group and Leitch. Broadcast also purchases cabinets
+and other fabricated parts and components from other third party suppliers.
+MAXxess Systems Inc.
+MAXxess Systems produces enterprise security management systems and
+electronic access control systems that meet the facility security needs of
+institutional, commercial, industrial and retail users. MAXxess sells a full
+line of electronic access control products consisting of software, hardware and
+digital video badging technologies. During the year ended March 31, 2002,
+MAXxess introduced its Environmental Security Systems that integrate its base
+AXxess 202 system with new detection technologies for toxic chemicals, gases and
+narcotics, in addition to video-based detection of smoke and unauthorized
+vehicles. MAXxess believes that its Environmental Security Systems provide
+enhanced levels of monitoring, control and detection that will be required in
+public facilities including buildings, airports, ports and for other high value
+assets.
+2
+Sales, Marketing and Principal Customers. MAXxess markets and sells its
+products globally through a network of system integrators. In the United States,
+MAXxess has three regional sales managers who oversee three geographical regions
+and manage the integrators. MAXxess operates a full service branch office in
+Windsor U.K. which serves the sales needs of the EMEA region. The Windsor office
+also provides local product availability and technical support for the region.
+Manufacturing and Materials. MAXxess maintains a dedicated manufacturing
+area located within our principal facilities in Anaheim, California. MAXxess
+maintains infrastructure to support production and inventory control,
+purchasing, quality assurance and manufacturing engineering at our Anaheim
+facilities.
+Telecom Products - Zyfer, Inc.
+Zyfer designs, develops and manufactures precision time and synchronization
+systems and products for network communications, computer networks and military
+command and control applications. Zyfer is under subcontract to provide NASA
+service support for space-borne digital data recorders. The space-borne digital
+recorders serviced by Zyfer used in on-board recording of flight systems for the
+U.S. Space Shuttle program.
+Zyfer's synchronization systems are based on GPS and oscillator
+technologies and are sold for applications in wireless networks and satellite
+communications for both commercial and government consumers. Significant
+customers of Zyfer include the U.S. government, government subcontractors and
+OEM suppliers to wireless carriers.
+Zyfer has developed a Gigabit network security processor called the
+SKP-100S. This product, anticipated to be the first of a family of products, is
+built around a proprietary network security processor technology called
+StealthKey. Typical applications are for network security, specifically storage
+area networks. Zyfer believes that the StealthKey technology has key performance
+advantages including automatic and transparent key generation, ease of
+implementation, and the ability to operate at wire speed.
+Sales, Marketing and Principal Customers. Zyfer conducts its selling and
+marketing activities directly from our principal facilities in Anaheim,
+California, and sells its synchronization products primarily through
+manufacturers' representatives.
+Manufacturing and Materials. Zyfer's manufacturing processes are ISO 9001
+certified. Most of its manufacturing processes consist of final assembly and
+test, which are conducted at our Anaheim, California facilities. Zyfer
+outsources board assembly and some preliminary fabrication processes.
+ITS Products - Iteris, Inc.
+Iteris, Inc. designs, develops, markets and implements sensors and systems
+for surface transportation. Using its proprietary software and ITS industry
+expertise, Iteris provides video sensor systems and transportation management
+and traveler information systems for the ITS industry. The ITS industry is
+comprised of companies applying a variety of technologies to enable the safe and
+efficient movement of people and goods. Iteris uses its outdoor image
+recognition software expertise to develop proprietary algorithms for video
+sensor systems that improve vehicle safety and the flow of traffic. Our
+knowledge of the ITS industry enables Iteris to design and implement
+transportation solutions that help public agencies reduce traffic congestion and
+provide greater access to traveler information.
+Iteris' proprietary image recognition systems include AutoVue and Vantage.
+AutoVue is a small windshield mounted sensor that utilizes proprietary software
+to detect and warn drivers of unintended lane departures. Iteris believes that
+AutoVue is a broad sensor platform that, through additional software
+development, may be expanded to incorporate additional safety and convenience
+features. Vantage is a video vehicle sensing system that detects the presence of
+vehicles at signalized intersections enabling a more efficient allocation of
+green signal time.
+Iteris' transportation management systems services business designs,
+develops and implements software-based systems that integrate sensors, video
+surveillance, computers and advanced communications equipment enabling public
+agencies to monitor, control and direct traffic flow, assist in the quick
+dispatch of emergency crews and distribute real-time information about traffic
+conditions.
+3
+Sales, Marketing and Principal Customers. Iteris markets and sells its
+transportation management systems and services directly to government agencies
+pursuant to negotiated contracts that involve competitive bidding and specific
+qualification requirements. Sales of Iteris' systems contracts generally involve
+long lead times and require extensive specification development, evaluation and
+price negotiations.
+Iteris sells its Vantage vehicle detection systems primarily through
+indirect sales channels comprised of independent dealers in the United States
+and Canada who sell integrated solutions and related products to the traffic
+intersection market. The independent dealers for Iteris are primarily
+responsible for sales, installation and support of Vantage systems. These
+dealers maintain an inventory of demonstration traffic products including the
+Vantage vehicle detection systems and sell directly to government agencies and
+installation contractors. These dealers often have long-term arrangements with
+the government agencies in their territory for the supply of various products
+for the construction and renovation of traffic intersections. Iteris holds
+technical training classes for its dealers and maintains a full-time staff of
+customer support technicians to provide technical assistance when needed.
+The marketing strategy for AutoVue is to establish it as the leading
+platform for in vehicle video sensing for trucks and passenger cars. AutoVue is
+sold directly by Iteris to vehicle manufacturers and major automotive suppliers.
+Iteris currently has a direct sales force for AutoVue consisting of two product
+managers. Product managers are supported by project and applications engineers
+who are responsible for applications and customer support.
+Manufacturing and Materials. Iteris designs, assembles and tests the
+components of its Vantage systems in approximately 6,000 square feet of space at
+our Anaheim facility. Production equipment consists of assembly lines and test
+apparatus for final assembly and testing of the manufactured product. Production
+volume is based upon quarterly forecasts that Iteris readjusts on a monthly
+basis to control inventory. Iteris subcontracts the manufacture of its AutoVue
+systems to one manufacturer. Iteris intends to engage additional manufacturers
+with expertise in high volume production to produce higher volumes for light and
+medium trucks and passenger cars. Iteris does not manufacture any of the
+hardware used in the transportation management and traveler information systems
+that it designs and implements. The production facility for Iteris is ISO 9001
+certified.
+Customer Support and Services
+Each of our business units is responsible for its own customer support and
+service organizations. We provide warranty service for each of our product
+lines, as well as follow-up service and support, for which we typically charge
+separately. We also offer separate software maintenance agreements to our
+customers. We view customer support services as a critical competitive factor as
+well as a revenue source.
+Backlog
+Our backlog of unfulfilled firm orders was approximately $42.7 million as
+of March 31, 2002 and was approximately $31.0 million as of March 31, 2001.
+Approximately 68% of our backlog at March 31, 2001 was recognized as revenues in
+the fiscal year ended March 31, 2002, and approximately 67% of our backlog at
+March 31, 2002 is expected to be recognized as revenues in the fiscal year ended
+March 31, 2003. Pursuant to the customary terms of our agreements with
+government contractors and other customers, customers can generally cancel or
+reschedule orders with little or no penalties. Lead times for the release of
+purchase orders depend upon the scheduling and forecasting practices of our
+individual customers, which also can affect the timing of the conversion of our
+backlog into revenues. For these reasons, among others, our backlog at a
+particular date may not be indicative of our future revenues.
+Product Development
+Each of our business units directs and staffs its own product development
+activities. Most of our development activities are conducted at our principal
+facilities in Anaheim, California. Our business units have historically required
+substantial ongoing research and development expenditures and other product
+development activities. Our company-sponsored research and development costs and
+expenses were approximately $13.0 million in fiscal 2000, $13.8 million in
+fiscal 2001 and $8.1 million in fiscal 2002. We expect to continue to pursue
+significant product development programs and incur significant research and
+development expenditures in each of our business units.
+4
+Competition
+Our business units generally face significant competition in each of their
+respective markets. Increased competition may result in price reductions,
+reduced gross margins and loss of market share, any of which could have a
+material adverse effect on our business, financial condition and results of
+operations.
+Broadcast's primary competitors include Sony, Harris, Encoda and Probel.
+Sony is a large, international supplier of extensive professional quality
+products. Harris and Probel principally provide automation control for video
+libraries and disk recorders. Broadcast's systems compete primarily in the arena
+of facility management and enterprise wide automation. We believe that the
+capability of our systems to integrate the broadcast station business systems
+acquisition processes, storage devices and presentation devices under a
+relational database management system represents a unique and differentiable
+capability.
+MAXxess principally competes with Casi-Rusco, Checkpoint, Cardkey, Lenel
+and Northern Computers in the sale of access control systems. MAXxess generally
+competes on the basis of its distributed processing system architecture, an open
+system that readily integrates other security subsystems and new detection
+capabilities, and a superior operator interface.
+Zyfer's primary competition for network synchronization products is Datum,
+Inc. and TrueTime Inc.
+While we believe that AutoVue is the only commercially-available lane
+departure warning system, potential competitors of Iteris include Delphi
+Automotive Systems Corporation domestically, NEC Corporation and Hitachi Ltd. in
+Japan and Robert Bosch Gmbh in Europe, which are currently developing video
+sensor technologies for the vehicle industry that could be used for lane
+departure warning systems. In the market for our Vantage vehicle detection
+systems, Iteris competes with manufacturers of both "above ground" video camera
+detection systems, such as Econolite Control Products, Inc., Trafficon, N.V. and
+the Peek Traffic Systems, and other non-intrusive detection devices including
+microwave, infrared, ultrasonic and magnetic detectors, as well as manufacturers
+and installers of in-pavement inductive loop products.
+The transportation management and traveler information systems market is
+highly fragmented and is subject to evolving national and regional quality and
+safety standards. Iteris' competitors vary in number, scope and breadth of the
+products and services they offer. Iteris' competitors in advanced transportation
+management and traveler information systems include corporations such as
+Transcore, Lockheed Martin Corporation, PB Farradyne Inc., Kimley-Horn and
+Associates, Inc. and National Engineering Technology, Inc. Iteris' competitors
+in transportation engineering, planning and design include major firms such as
+Parsons Brinkerhoff, Inc. and Parsons Transportation Group Inc., as well as many
+regional engineering firms.
+In general, the markets for the products and services offered by our
+businesses are highly competitive and are characterized by rapidly changing
+technology and evolving standards. Many of our current and prospective
+competitors have longer operating histories, greater name recognition, access to
+larger customer bases and significantly greater financial, technical,
+manufacturing, distribution and marketing resources than us. As a result, they
+may be able to adapt more quickly to new or emerging standards or technologies
+or to devote greater resources to the promotion and sale of their products. It
+is also possible that new competitors or alliances among competitors could
+emerge and rapidly acquire significant market share. We believe that our ability
+to compete effectively in our target markets depends on a number of factors,
+including the success and timing of our new product development, the
+compatibility of our products with a broad range of computing systems, product
+quality and performance, reliability, functionality, price, and service and
+technical support. Our failure to provide services and develop and market
+products that compete successfully with those of other suppliers and consultants
+in our target markets would have a material adverse effect on our business,
+financial condition and results of operations.
+Intellectual Property and Proprietary Rights
+Our ability to compete effectively depends in part on our ability to
+develop and maintain the proprietary aspects of our technology. Our policy is to
+obtain appropriate proprietary rights protection for any potentially significant
+new technology acquired or developed each of our business units. We currently
+hold a number of United States and foreign patents and trademarks, which will
+expire at various dates commencing in 2004. We also have pending a number of
+United States and foreign patent applications relating to certain of our
+products; however, we cannot be certain that any patents will be granted
+pursuant to these applications.
+5
+In addition to patent laws, we rely on copyright and trade secret laws to
+protect our proprietary rights. We attempt to protect our trade secrets and
+other proprietary information through agreements with customers and suppliers,
+proprietary information agreements with our employees and consultants, and other
+similar measures. We cannot be certain that we will be successful in protecting
+our proprietary rights. While we believe our patents, patent applications,
+software and other proprietary know-how have value, changing technology makes
+our future success dependent principally upon our employees' technical
+competence and creative skills for continuing innovation.
+Litigation has been necessary in the past and may be necessary in the
+future to enforce our proprietary rights, to determine the validity and scope of
+the proprietary rights of others, or to defend us against claims of infringement
+or invalidity by others. An adverse outcome in such litigation or similar
+proceedings could subject us to significant liabilities to third parties,
+require disputed rights to be licensed from others or require us to cease
+marketing or using certain products, any of which could have a material adverse
+effect on our business, financial condition and results of operations. In
+addition, the cost of addressing any intellectual property litigation claim,
+both in legal fees and expenses, as well as from the diversion of management's
+resources, regardless of whether the claim is valid, could be significant and
+could have a material adverse effect on our business, financial condition and
+results of operations.
+Employees
+We refer to our employees as associates. As of June 17, 2002, Odetics and
+its subsidiaries employed an aggregate of 315 associates, including 77
+associates in general management, administration and finance; 36 associates in
+sales and marketing; 132 associates in product development; 58 associates in
+operations, manufacturing and quality; and 12 associates in customer service.
+None of our associates are represented by a labor union, and we have never
+experienced a work stoppage.
+We provide centralized support for human resources management for each of
+our business units and subsidiaries. These services include recruiting,
+administration and outplacement.
+Government Regulation
+Our manufacturing operations are subject to various federal, state and
+local laws, including those restricting the discharge of materials into the
+environment. We are not involved in any pending or threatened proceedings which
+would require curtailment of our operations because of such regulations. We
+continue to expend funds in connection with our compliance with applicable
+environmental regulations. These expenditures have not, however, been
+significant in the past, and we do not expect any significant expenditures in
+the near future.
+From time to time, a portion of our work relating to network
+synchronization systems may constitute classified United States government
+information or may be used in classified programs of the United States
+Government. For this purpose, we possess certain relevant security clearances.
+Our affected facilities and operations are also subject to security regulations
+of the United States Government. We believe we are currently in full compliance
+with these regulations.
+6
+RISK FACTORS
+Before deciding to invest in Odetics or to maintain or increase your
+investment, you should carefully consider the risks described below, in addition
+to the other information contained in this report and in our other filings with
+the SEC, including our reports on Forms 10-Q and 8-K. The risks and
+uncertainties described below are not the only ones facing us. Additional risks
+and uncertainties not presently known to us or that we currently deem immaterial
+may also affect our business operations. If any of these risks actually occur,
+our business, financial condition or results of operations could be seriously
+harmed. In that event, the market price for our common stock could decline and
+you may lose all or part of your investment.
+We Have Experienced Substantial Losses and Expect Future Losses. We
+experienced operating losses of $10.8 million the year ended March 31, 2002,
+$37.9 million for the year ended March 31, 2001 and $32.9 million for the year
+ended March 31, 2000. In the quarter ended September 30, 2001, we downsized our
+business in connection with our sale of the Gyyr CCTV Products division and the
+discontinuation of the business of our Mariner Networks subsidiary and the
+reorganization of our European operations. We cannot assure you that our efforts
+to downsize our operations will improve our financial performance, or that we
+will be able to achieve profitability on a quarterly or annual basis in the
+future. Most of our expenses are fixed in advance, and we generally are unable
+to reduce our expenses significantly in the short-term to compensate for any
+unexpected delay or decrease in anticipated revenues. As a result, we may
+continue to experience losses, which would make it difficult to fund our
+operations and achieve our business plan, and could cause the market price of
+our common stock to decline.
+We Will Need to Raise Additional Capital in the Future and May Not Be Able
+to Secure Adequate Funds on Terms Acceptable to Us, or at All. We have generated
+significant net losses in recent periods, and have experienced negative cash
+flows from operations in the amount of $18.2 million for the year ended March
+31, 2002 and $20.1 million for the year ended March 31, 2001. Although we
+completed the sale of our Anaheim, California property in May 2002, the majority
+of the proceeds of such sale were used to repay outstanding short-term
+indebtedness. We anticipate that we will need to raise additional capital in the
+future. Our Iteris subsidiary currently maintains a line of credit with a
+maximum availability of $5.0 million, which expires in August 2004.
+Substantially all of the assets of Iteris have been pledged to the lender to
+secure the outstanding indebtedness under this facility (although there were no
+amounts outstanding under the line of credit at June 21, 2002). Even though we
+retired the Odetics line of credit in the quarter ended December 31, 2001, we
+also incurred cash obligations in the amount of $3.0 million payable over the
+next seven months related to the discontinuation of Mariner Networks and the
+reorganization of our European operations. We plan to raise additional capital
+in the near future, either through bank borrowings, other debt or equity
+financings, or the divestiture of business units or select assets. We cannot
+assure you that any additional capital will be available on a timely basis, on
+acceptable terms, or at all. These conditions, together with our recurring
+losses and cash requirements, raise substantial doubt about our ability to
+continue as a going concern.
+Our capital requirements will depend on many factors, including:
+. our ability to control costs;
+. market acceptance of our products and the overall level of sales of our
+products;
+. our ability to generate operating income;
+. increased research and development funding, and required investments in
+our business units;
+. increased sales and marketing expenses;
+. technological advancements and our competitors' response to our
+products;
+. capital improvements to new and existing facilities;
+. potential acquisitions of businesses and product lines;
+. our relationships with customers and suppliers; and
+7
+. general economic conditions including the effects of the current
+economic slowdown and international conflicts.
+If our capital requirements are materially different from those currently
+planned, we may need additional capital sooner than anticipated. If additional
+funds are raised through the issuance of equity or convertible debt securities,
+the percentage ownership of our stockholders will be reduced and such securities
+may have rights, preferences and privileges senior to our common stock.
+Additional financing may not be available on favorable terms or at all. If
+adequate funds are not available or are not available on acceptable terms, we
+may be unable to continue our operations as planned, develop or enhance our
+products, expand our sales and marketing programs, take advantage of future
+opportunities or respond to competitive pressures.
+The Trading Price of Our Common Stock Is Volatile. The trading price of our
+common stock has been subject to wide fluctuations in the past. Since January
+2000, our common stock has traded at prices as low as $1.27 per share and as
+high as $29.44 per share. In April 2002, because we failed to meet the minimum
+stockholder's equity requirement for continued listing on the Nasdaq National
+Market, both our Class A common stock and Class B common stock were delisted
+from the Nasdaq National Market and subsequently approved for listing on the
+Nasdaq SmallCap Market. If our stock price continues to decline or declines
+below $1.00 per share for a period of time, our common stock could be subject to
+delisting from the Nasdaq SmallCap Market and there may not be a market for our
+stock. We may not be able to increase or sustain the current market price of our
+common stock in the future. As such, you may not be able to resell your shares
+of common stock at or above the price you paid for them. The market price of our
+common stock could continue to fluctuate in the future in response to various
+factors, including, but not limited to:
+. quarterly variations in operating results;
+. our ability to control costs and improve cash flow;
+. shortages announced by suppliers;
+. announcements of technological innovations or new products by our
+competitors, customers or us;
+. acquisitions or businesses, products or technologies;
+. changes in pending litigation or new litigation;
+. changes in investor perceptions;
+. our ability to spin-off any business unit;
+. applications or product enhancements by us or by our competitors; and
+. changes in earnings estimates or investment recommendations by
+securities analysts.
+The stock market in general has recently experienced volatility, which has
+particularly affected the market prices of equity securities of many high
+technology companies. This volatility has often been unrelated to the operating
+performance of these companies. These broad market fluctuations may adversely
+affect the market price of our common stock. In the past, companies that have
+experienced volatility in the market price of their securities have been the
+subject of securities class action litigation. If we were to become the subject
+of a class action lawsuit, it could result in substantial losses and divert
+management's attention and resources from other matters.
+We Depend on Government Contracts and Subcontracts and Face Additional
+Risks Related to Fixed Price Contracts. A significant portion of the sales by
+Iteris and a portion of our sales by Zyfer were derived from contracts with
+governmental agencies, either as a general contractor, subcontractor or
+supplier. Government contracts represented approximately 24%, 26% and 38% of our
+total net sales and contract revenues for the years ended March 31, 2000, 2001
+and 2002, respectively. We anticipate that revenue from government contracts
+will continue to increase in the near future. Government business is, in
+general, subject to special risks and challenges, including:
+8
+. long purchase cycles or approval processes;
+. competitive bidding and qualification requirements;
+. performance bond requirements;
+. changes in government policies and political agendas;
+. delays in funding, budgetary constraints and cut-backs; and
+. milestone requirements and liquidated damage provisions for failure to
+meet contract milestones.
+In addition, a large number of our government contracts are fixed price
+contracts. As a result, we may not be able to recover for any cost overruns.
+These fixed price contracts require us to estimate the total project cost based
+on preliminary projections of the project's requirements. The financial
+viability of any given project depends in large part on our ability to estimate
+these costs accurately and complete the project on a timely basis. In the event
+our costs on these projects exceed the fixed contractual amount, we will be
+required to bear the excess costs. These additional costs adversely affect our
+financial condition and results of operations. Moreover, certain of our
+government contracts are subject to termination or renegotiation at the
+convenience of the government, which could result in a large decline in our net
+sales in any given quarter. Our inability to address any of the foregoing
+concerns or the loss or renegotiation of any material government contract could
+seriously harm our business, financial condition and results of operations.
+We are Exposed to the Risks Associated with the Recent Worldwide Economic
+Slowdown and Related Uncertainties. Concerns about inflation, decreased consumer
+confidence, reduced corporate profits and capital spending, and recent
+international conflicts and terrorist and military actions have resulted in a
+downturn in worldwide economic conditions, particularly in the United States. As
+a result of these unfavorable economic conditions, we have experienced a
+slowdown in customer orders, cancellations and rescheduling of backlog and
+higher overhead costs. In addition, recent political and social turmoil related
+to international conflicts and terrorist acts can be expected to put further
+pressure on economic conditions in the U.S. and worldwide. These political,
+social and economic conditions make it extremely difficult for our customers,
+our suppliers and us to accurately forecast and plan future business activities.
+If such conditions continue or worsen, our business, financial condition and
+results of operations will likely be materially and adversely affected.
+Our Quarterly Operating Results Fluctuate as a Result of Many Factors. Our
+quarterly revenues and operating results have fluctuated and are likely to
+continue to vary from quarter to quarter due to a number of factors, many of
+which are not within our control. Factors that could affect our revenues
+include, among others, the following:
+. our ability to raise additional capital;
+. our significant investment in research and development for our
+subsidiaries and business units;
+. our ability to control costs;
+. international conflicts and acts of terrorism;
+. our ability to develop, introduce, market and gain market acceptance of
+new products applications and product enhancements in a timely manner;
+. the size, timing, rescheduling or cancellation of significant customer
+orders;
+. the introduction of new products by competitors;
+. the availability of components used in the manufacture of our products;
+. changes in our pricing policies and the pricing policies by our
+suppliers and competitors, pricing concessions on volume sales, as well
+as increased price competition in general;
+9
+. the long lead times associated with government contracts or required by
+vehicle manufacturers;
+. our success in expanding and implementing our sales and marketing
+programs;
+. the effects of technological changes in our target markets;
+. our relatively small level of backlog at any given time;
+. the mix of sales among our business units;
+. deferrals of customer orders in anticipation of new products,
+applications or product enhancements;
+. the risks inherent in our acquisitions of technologies and businesses;
+. risks and uncertainties associated with our international business;
+. currency fluctuations and our ability to get currency out of certain
+foreign countries; and
+. general economic and political conditions.
+In addition, our sales in any quarter may consist of a relatively small
+number of large customer orders. As a result, the timing of a small number of
+orders may impact our quarter-to-quarter results. The loss of or a substantial
+reduction in orders from any significant customer could seriously harm our
+business, financial condition and results of operations.
+Due to all of the factors listed above and other risks discussed in this
+report, our future operating results could be below the expectations of
+securities analysts or investors. If that happens, the trading price of our
+common stock could decline. As a result of these quarterly variations, you
+should not rely on quarter-to-quarter comparisons of our operating results as an
+indication of our future performance.
+Our Operating Strategy for Developing Companies is Expensive and May Not Be
+Successful. Our business strategy historically has required us to make
+significant investments in our business units. These investments are expensive
+and require the commitment of significant time and resources. We expect to
+continue to invest in the development of certain of our business units with the
+goal of achieving profitability in each of our business units, and to a lesser
+extent, to monetize those business units for the benefit of our stockholders
+through an initial public offering, spin-off or sale to a strategic buyer. We
+may not recognize the benefits of this investment for a significant period of
+time, if at all. Our ability to achieve profitability in any business unit, to
+complete any private or public offerings of securities by any of our business
+units, and/or to spin-off our interest in the business unit to our stockholders
+will depend upon many factors, including:
+. the overall performance and results of operations of the particular
+business unit;
+. the potential market for our business unit;
+. our ability to assemble and retain a qualified management team for the
+business unit;
+. our financial position and cash requirements;
+. the business unit's customer base and product line;
+. the current tax treatment of spin-off and sale transactions, and our
+ability to obtain favorable determination letters from the Internal
+Revenue Service; and
+. general economic and market conditions, including the receptiveness of
+the stock markets to initial public offerings and private placements.
+We may not be able to achieve profitability in our business units, to
+complete a successful private or public offering or to spin-off of any of our
+business units in the near future, or at all. During fiscal 2001, we attempted
+to complete the initial public offering of Iteris, but withdrew the offering due
+to adverse market conditions. Even if we
+10
+are able to achieve profitability and the market is receptive to public
+offerings, we may decide not to complete any further offerings, spin-off a
+particular business unit, or delay the spin-off until a later date.
+We Must Keep Pace with Rapid Technological Change to Remain Competitive.
+Our target markets are in general characterized by the following factors:
+. rapid technological advances;
+. downward price pressure in the marketplace as technologies mature;
+. changes in customer requirements;
+. frequent new product introductions and enhancements; and
+. evolving industry standards and changes in the regulatory environment.
+Our future success will depend upon our ability to anticipate and adapt to
+changes in technology and industry standards, and to effectively develop,
+introduce, market and gain broad acceptance of new products and product
+enhancements incorporating the latest technological advancements.
+We believe that we must continue to make substantial investments to support
+ongoing research and development in order to remain competitive. We need to
+continue to develop and introduce new products that incorporate the latest
+technological advancements in hardware, storage media, operating system software
+and applications software in response to evolving customer requirements. Our
+business and results of operations could be adversely affected if we do not
+anticipate or respond adequately to technological developments or changing
+customer requirements. We cannot assure you that any such investments in
+research and development will lead to any corresponding increase in revenue.
+Our Future Success Depends on the Successful Development and Market
+Acceptance of New Products. We believe our revenue growth and future operating
+results will depend on our ability to complete development of new products and
+enhancements, introduce these products in a timely, cost-effective manner,
+achieve broad market acceptance of these products and enhancements, and reduce
+our product costs. We may not be able to introduce any new products or any
+enhancements to our existing products on a timely basis, or at all. In addition,
+the introduction of any new products could adversely affect the sales of our
+certain of our existing products.
+Our future success will also depend in part on the success of several
+recently introduced products including CommSync II, a Zyfer solution for secure,
+high speed, point-to-point communications; AutoVue, our lane departure warning
+system; and AIRO 9.0, our broadcast automation solution. Market acceptance of
+our new products depends upon many factors, including our ability to accurately
+predict market requirements and evolving industry standards, our ability to
+resolve technical challenges in a timely and cost-effective manner and achieve
+manufacturing efficiencies, the perceived advantages of our new products over
+traditional products and the marketing capabilities of our independent
+distributors and strategic partners. Our business and results of operations
+could be seriously harmed by any significant delays in our new product
+development. Certain of our new products could contain undetected design faults
+and software errors or "bugs" when first released by us, despite our testing. We
+may not discover these faults or errors until after a product has been installed
+and used by our customers. Any faults or errors in our existing products or in
+any new products may cause delays in product introduction and shipments, require
+design modifications or harm customer relationships, any of which could
+adversely affect our business and competitive position.
+Iteris currently outsources the manufacture of its AutoVue product line to
+a single manufacturer. This manufacturer may not be able to produce sufficient
+quantities of this product in a timely manner or at a reasonable cost, which
+could materially and adversely affect our ability to launch or gain market
+acceptance of AutoVue.
+We Have Significant International Sales and Are Subject to Risks Associated
+with Operating in International Markets. International sales represented 10% of
+our net sales and contract revenues for the fiscal year ended March 31, 2002,
+20% for the fiscal year ended March 31, 2001, and 20% for the fiscal year ended
+March 31, 2000. During the fiscal year ended March 31, 2002, we reorganized our
+European operations, which included the discontinuation of our Odetics Europe
+Ltd., MAXxess Europe Ltd., Mariner France and Mariner Europe Ltd.
+11
+operations, and the transition of our Broadcast and MAXxess international
+operations to branch office operations with the intent of lowering our
+international costs. This reorganization may result in significantly lower
+international sales in future periods and unanticipated liabilities related to
+the closures and we may not achieve the anticipated cost savings. We may also
+face challenges in managing and transitioning our international operations due
+to our limited experience operating through branch offices. In addition, the
+recent terrorist attacks in the United States and heightened security may
+adversely impact our international sales and could make our international
+operations more expensive.
+International business operations are also subject to other inherent risks,
+including, among others:
+. unexpected changes in regulatory requirements, tariffs and other trade
+barriers or restrictions;
+. longer accounts receivable payment cycles;
+. difficulties in managing and staffing international operations;
+. potentially adverse tax consequences;
+. the burdens of compliance with a wide variety of foreign laws;
+. import and export license requirements and restrictions of the United
+States and each other country in which we operate;
+. exposure to different legal standards and reduced protection for
+intellectual property rights in some countries;
+. currency fluctuations and restrictions; and
+. political, social and economic instability.
+We believe that international sales will continue to represent a
+significant portion of our revenues, and that continued growth and profitability
+may require further expansion of our international operations. Nearly all of our
+international sales from this point on are denominated in U.S. dollars. As a
+result, an increase in the relative value of the dollar could make our products
+more expensive and potentially less price competitive in international markets.
+We do not engage in any transactions as a hedge against risks of loss due to
+foreign currency fluctuations.
+Any of the factors mentioned above may adversely effect our future
+international sales and, consequently, effect our business, financial condition
+and operating results. Furthermore, as we increase our international sales, our
+total revenues may also be affected to a greater extent by seasonal fluctuations
+resulting from lower sales that typically occur during the summer months in
+Europe and other parts of the world.
+We Need to Manage Operations and the Integration of Our Acquisitions. Over
+the past few years, we have expanded our operations and made several substantial
+acquisitions of diverse businesses, including Intelligent Controls, Inc.,
+International Media Integration Services, Ltd., Meyer Mohaddes Associates, Inc.,
+Viggen Corporation, and certain assets of the Transportation Systems business of
+Rockwell International. We may engage in acquisitions of complementary
+businesses, products and technologies. Acquisitions may require significant
+capital infusions and, in general, acquisitions also involve a number of special
+risks, including:
+. potential disruption of our ongoing business and the diversion of our
+resources and management's attention;
+. the failure to retain or integrate key acquired personnel;
+. the challenge of assimilating diverse business cultures, and the
+difficulties in integrating the operations, technologies and
+information system of the acquired companies;
+. increased costs to improve managerial, operational, financial and
+administrative systems and to eliminate duplicative services;
+12
+. the incurrence of unforeseen obligations or liabilities;
+. potential impairment of relationships with employees or customers as a
+result of changes in management; and
+. increased interest expense and amortization of acquired intangible
+assets.
+Acquisitions may also materially and adversely affect our operating results
+due to large write-offs, contingent liabilities, substantial depreciation,
+deferred compensation charges or goodwill amortization, or other adverse tax or
+audit consequences. Our failure to manage growth and integrate our acquisitions
+successfully could adversely affect our business, financial condition and
+results of operations.
+Our competitors are also soliciting potential acquisition candidates, which
+could both increase the price of any acquisition targets and decrease the number
+of attractive companies available for acquisition. We cannot assure you that we
+will be able to consummate any additional acquisitions, successfully integrate
+any acquisitions or realize the benefits anticipated from any acquisition.
+The Markets in Which We Operate Are Highly Competitive and Have Many More
+Established Competitors. We compete with numerous other companies in our target
+markets and we expect such competition to increase due to technological
+advancements, industry consolidations and reduced barriers to entry. Increased
+competition is likely to result in price reductions, reduced gross margins and
+loss of market share, any of which could seriously harm our business, financial
+condition and results of operations. Many of our competitors have far greater
+name recognition and greater financial, technological, marketing and customer
+service resources than we do. This may allow them to respond more quickly to new
+or emerging technologies and changes in customer requirements. It may also allow
+them to devote greater resources to the development, promotion, sale and support
+of their products than we can. Recent consolidations of end users, distributors
+and manufacturers in our target markets have exacerbated this problem. As a
+result of the foregoing factors, we may not be able to compete effectively in
+our target markets and competitive pressures could adversely affect our
+business, financial condition and results of operations.
+We Cannot Be Certain of Our Ability to Attract and Retain Key Personnel and
+We Do Not Have Employment Agreements with Any Key Personnel. Due to the
+specialized nature of our business, we are highly dependent on the continued
+service of our executive officers and other key management, engineering and
+technical personnel, particularly Joel Slutzky, our Chairman of the Board, who
+recently retired as our Chief Executive Officer, and Gregory A. Miner, our Chief
+Executive Officer and Chief Financial Officer. The leadership transition between
+Mr. Slutzky and Mr. Miner could adversely affect our business. We do not have
+any employment contracts with any of our officers or key employees. The loss of
+any of these individuals could adversely affect our business, financial
+condition or results of operations.
+Our success will also depend in large part upon our ability to continue to
+attract, retain and motivate qualified engineering and other highly skilled
+technical personnel. Competition for employees, particularly development
+engineers, is intense. We may not be able to continue to attract and retain
+sufficient numbers of such highly skilled employees. Our inability to attract
+and retain additional key employees or the loss of one or more of our current
+key employees could adversely affect upon our business, financial condition and
+results of operations.
+We May Not be Able to Adequately Protect or Enforce Our Intellectual
+Property Rights. If we are not able to adequately protect or enforce the
+proprietary aspects of our technology, competitors could be able to access our
+proprietary technology and our business, financial condition and results of
+operations will likely be seriously harmed. We currently attempt to protect our
+technology through a combination of patent, copyright, trademark and trade
+secret laws, employee and third party nondisclosure agreements and similar
+means. Despite our efforts, other parties may attempt to disclose, obtain or use
+our technologies or solutions. Our competitors may also be able to independently
+develop products that are substantially equivalent or superior to our products
+or design around our patents. In addition, the laws of some foreign countries do
+not protect our proprietary rights as fully as do the laws of the United States.
+As a result, we may not be able to protect our proprietary rights adequately in
+the United States or abroad.
+From time to time, we have received notices that claim we have infringed
+upon the intellectual property of others. Even if these claims are not valid,
+they could subject us to significant costs. We have engaged in litigation in the
+past, and litigation may be necessary in the future to enforce our intellectual
+property rights or to determine
+13
+the validity and scope of the proprietary rights of others. Litigation may also
+be necessary to defend against claims of infringement or invalidity by others.
+An adverse outcome in litigation or any similar proceedings could subject us to
+significant liabilities to third parties, require us to license disputed rights
+from others or require us to cease marketing or using certain products or
+technologies. We may not be able to obtain any licenses on terms acceptable to
+us, or at all. We also may have to indemnify certain customers or strategic
+partners if it is determined that we have infringed upon or misappropriated
+another party's intellectual property. Any of these results could adversely
+affect on our business, financial condition and results of operations. In
+addition, the cost of addressing any intellectual property litigation claim,
+both in legal fees and expenses, and the diversion of management resources,
+regardless of whether the claim is valid, could be significant and could
+seriously harm our business, financial condition and results of operations.
+We Are Controlled by Certain of Our Officers and Directors. As of June 21,
+2002, our officers and directors beneficially owned approximately 24% of the
+total combined voting power of the outstanding shares of our Class A common
+stock and Class B common stock. As a result of their stock ownership, our
+management will be able to significantly influence the election of our directors
+and the outcome of corporate actions requiring stockholder approval, such as
+mergers and acquisitions, regardless of how our other stockholders may vote.
+This concentration of voting control may have a significant effect in delaying,
+deferring or preventing a change in our management or change in control and may
+adversely affect the voting or other rights of other holders of common stock.
+Our Stock Structure and Certain Anti-Takeover Provisions May Affect the
+Price of Our Common Stock. Certain provisions of our certificate of
+incorporation and our stockholder rights plan could make it difficult for a
+third party to acquire us, even though an acquisition might be beneficial to our
+stockholders. These provisions could limit the price that investors might be
+willing to pay in the future for shares of our common stock. Our Class A common
+stock entitles the holder to one-tenth of one vote per share and our Class B
+common stock entitles the holder to one vote per share. The disparity in the
+voting rights between our common stock, as well as our insiders' significant
+ownership of the Class B common stock, could discourage a proxy contest or make
+it more difficult for a third party to effect a change in our management and
+control. In addition, our Board of Directors is authorized to issue, without
+stockholder approval, up to 2,000,000 shares of preferred stock with voting,
+conversion and other rights and preferences superior to those of our common
+stock, as well as additional shares of Class B common stock. Our future issuance
+of preferred stock or Class B common stock could be used to discourage an
+unsolicited acquisition proposal.
+In March 1998, we adopted a stockholder rights plan and declared a dividend
+of preferred stock purchase rights to our stockholders. In the event a third
+party acquires more than 15% of the outstanding voting control of our company or
+15% of our outstanding common stock, the holders of these rights will be able to
+purchase the junior participating preferred stock at a substantial discount off
+of the then current market price. The exercise of these rights and purchase of a
+significant amount of stock at below market prices could cause substantial
+dilution to a particular acquiror and discourage the acquiror from pursuing our
+company. The mere existence of a stockholder rights plan often delays or makes a
+merger, tender offer or proxy contest more difficult.
+We Do Not Pay Cash Dividends. We have never paid cash dividends on our
+common stock and do not anticipate paying any cash dividends on either class of
+our common stock in the foreseeable future.
+We May Be Subject to Additional Risks. The risks and uncertainties
+described above are not the only ones facing our company. Additional risks and
+uncertainties not presently known to us or that we currently deem immaterial may
+also adversely affect our business operations.
+ITEM 2. PROPERTIES.
+Our headquarters and principal operations are located in Southern
+California. In 1984, we purchased and renovated a two building complex
+containing approximately 257,900 square feet situated on approximately 14 acres
+located at 1515 and 1585 South Manchester Boulevard in Anaheim, California. Our
+facilities house our corporate and administrative offices (approximately 43,600
+dedicated square feet), as well as the operations of MAXxess and Broadcast,
+(approximately 35,000 dedicated square feet), Zyfer (approximately 56,300
+dedicated square feet), and Iteris (approximately 30,000 dedicated square feet).
+14
+In May 2002, we completed the sale and leaseback of our Anaheim Facilities
+for an aggregate sales price of $22.6 million. We entered into a 30-month lease
+for 1585 South Manchester for a monthly rental payment of $57,553, and a ten
+year lease for 1515 South Manchester for a monthly rental payment of $152,150.
+We intend to consolidate our operations to within approximately 140,000 square
+feet and sublease the remaining space in Anaheim to other tenants.
+Broadcast leases approximately 7,400 square feet in Austin, Texas primarily
+for service, sales support, and engineering. Iteris leases 8 office suites
+representing an aggregate of approximately 20,000 square feet within the United
+States for its support staff and development teams.
+We currently operate a single shift in each of our manufacturing and
+assembly facilities, and we believe that our facilities are adequate for our
+needs for at least the next twelve months.
+ITEM 3. LEGAL PROCEEDINGS.
+We are not currently a party to any material legal proceedings.
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
+No matters were submitted to a vote of our security holders during the
+three months ended March 31, 2002.
+15
+PART II
+ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
+Since April 22, 2002, our Class A common stock and Class B common stock has
+been listed on the Nasdaq SmallCap Market under the symbols "ODETA" and "ODETB,"
+respectively. Prior to that, our Class A common stock and Class B common stock
+were listed on the Nasdaq National Market. The following table sets forth for
+the fiscal periods indicated the high and low sales prices for the Class A
+common stock and Class B common stock as reported by the Nasdaq SmallCap Market:
+Class A Class B
+Common Stock Common Stock
+------------ ------------
+High Low High Low
+---- --- ---- ---
+Fiscal Year Ended March 31, 2001
+First Quarter ......................................... $15.25 $ 7.88 $15.00 $10.00
+Second Quarter ........................................ 17.94 13.00 17.63 13.50
+Third Quarter ......................................... 17.00 5.53 17.00 5.63
+Fourth Quarter ........................................ 8.00 2.94 8.25 3.00
+Fiscal Year Ended March 31, 2002
+First Quarter ......................................... 4.50 2.19 4.59 3.13
+Second Quarter ........................................ 2.49 1.38 3.80 1.76
+Third Quarter ......................................... 1.97 1.13 2.59 1.41
+Fourth Quarter ........................................ 1.92 1.44 3.29 1.82
+Fiscal Year Ending March 31, 2002
+First Quarter (through June 27, 2002) ................. 1.67 1.32 2.30 1.85
+As of June 27, 2002, we had 508 holders of record of Class A common stock
+and 113 holders of record of Class B common stock according to information
+furnished by our transfer agent.
+Dividend Policy
+We have never paid or declared cash dividends on either class of our common
+stock, and have no current plans to pay such dividends in the foreseeable
+future. We currently intend to retain any earnings for working capital and
+general corporate purposes. The payment of any future dividends will be at the
+discretion of our Board of Directors, and will depend upon a number of factors,
+including, but not limited to, future earnings, the success of our business,
+activities, our capital requirements, our general financial condition and future
+prospects, general business conditions, the consent of our lender and such other
+factors as the Board may deem relevant.
+Recent Sales of Unregistered Securities
+During the quarter ended March 31, 2002, we did not sell or issue any
+unregistered securities.
+16
+ITEM 6. SELECTED FINANCIAL DATA.
+The following selected consolidated financial data with respect to our
+consolidated statement of operations for each of the five fiscal years in the
+period ended March 31, 2002 and the consolidated balance sheet data at March 31,
+1998, 1999, 2000, 2001 and 2002 are derived from our audited consolidated
+financial statements. The consolidated statements of operation data for the
+fiscal years ended March 31, 1998 and 1999 and the consolidated balance sheet
+data at March 31, 1998, 1999 and 2000 are not included in the consolidated
+financial statements included elsewhere in this report. The following
+information should be read in conjunction with "Management's Discussion and
+Analysis of Financial Condition and Results of Operations" and with our
+consolidated financial statements and the related notes thereto included
+elsewhere in this report.
+Fiscal Year Ended March 31,
+--------------------------------------------------------
+1998 1999 2000 2001 2002
+-------- -------- -------- -------- --------
+(in thousands, except per share data)
+Consolidated Statement of Operations Data:
+Net sales .................................................... $ 77,373 $ 64,805 $ 59,949 $ 56,119 $ 36,642
+Contract revenues ............................................ 10,284 13,331 18,666 20,039 22,846
+-------- -------- -------- -------- --------
+Total net sales and contract revenues ........................ 87,657 78,136 78,615 76,158 59,488
+Cost of sales ................................................ 53,663 46,939 49,147 44,869 22,245
+Cost of contract revenues .................................... 6,430 9,007 13,431 13,781 13,132
+Gross profit--net sales ...................................... 23,710 17,866 10,802 11,250 14,397
+Gross profit--contract revenues .............................. 3,854 4,324 5,235 6,258 9,714
+Total gross profit ........................................... 27,564 22,190 16,037 17,508 24,111
+Selling, general and administrative expenses ................. 25,052 29,872 35,938 35,398 24,570
+Research and development expenses ............................ 8,631 9,980 12,978 13,753 8,115
+In process research and development .......................... 2,106 -- -- -- --
+Special charge ............................................... 1,716 -- -- 6,285 2,189
+-------- -------- -------- -------- --------
+Loss from operations ......................................... (9,941) (17,662) (32,879) (37,928) (10,763)
+Non-operating income (expense):
+Royalty/other income ..................................... -- -- 38,437 19,055 2,864
+Interest expense, net ..................................... (617) (1,807) (2,048) (1,762) (4,190)
+-------- -------- -------- -------- --------
+Income (loss) before taxes ................................... (10,558) (19,469) 3,510 (20,635) (12,089)
+Income taxes (benefit) ....................................... (2,858) -- -- -- (785)
+Minority interest in earnings of subsidiary .................. -- -- -- -- 1,910
+-------- -------- -------- -------- --------
+Income (loss) from continuing operations ..................... (7,700) (19,469) 3,510 (20,635) (13,214)
+Income (loss) from discontinued operations, net of
+income tax ................................................ 1,106 (649) (5,789) (11,905) (12,924)
+Extraordinary loss from early extinguishment
+of debt, net .............................................. -- -- -- -- (450)
+-------- -------- -------- -------- --------
+Net loss .................................................... . $ (6,594) $(20,118) $ (2,279) $(32,540) $(26,588)
+======== ======== ======== ======== ========
+Diluted earnings (loss) per share:
+Continuing operations ..................................... $ (1.11) $ (2.49) $ 0.37 $ (2.07) $ (1.17)
+Discontinued operations ................................... 0.16 (0.08) (0.61) (1.19) (1.15)
+Extraordinary loss from the extinguishment of debt ........ -- -- -- -- (0.04)
+-------- -------- -------- -------- --------
+Loss per share ............................................ $ (0.95) $ (2.57) $ (0.24) $ (3.26) $ (2.36)
+======== ======== ======== ======== ========
+Shares used in calculating diluted earnings (loss) per share . 6,912 7,820 9,444 9,977 11,267
+======== ======== ======== ======== ========
+At March 31,
+--------------------------------------------------------
+1998 1999 2000 2001 2002
+---- ---- ---- ---- ----
+Consolidated Balance Sheet Data:
+Working capital (deficit) ................................... $ 22,076 $ 18,045 $ 15,763 $ (5,785) $ (9,327)
+Total assets ................................................ 88,760 81,355 81,850 68,061 52,238
+Long-term debt (less current portion) ....................... 21,000 19,962 11,666 4,800 2,042
+Accumulated deficit ......................................... (3,795) (23,913) (26,192) (58,732) (85,320)
+Total stockholders' equity .................................. 38,580 36,323 36,110 20,378 5,255
+17
+ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
+OF OPERATIONS.
+General
+We define our business segments as ITS, video products and telecom
+products. The ITS segment consists of our majority-owned subsidiary, Iteris,
+Inc. The video products segment includes our wholly-owned subsidiaries,
+Broadcast, Inc. and MAXxess Systems, Inc. (previously known as Gyyr
+Incorporated). The telecom products segment consists of Zyfer, Inc., our
+wholly-owned subsidiary (formerly known as our Communications division). In
+April 2001, Gyyr separated its operations into two divisions, the Gyyr CCTV
+Products division, which manufactures analog and digital storage solutions, and
+the Gyyr Electronic Access Control division, which manufactures enterprise
+security management systems. In September 2001, we sold substantially all of the
+assets and certain liabilities of the Gyyr CCTV Products division. In connection
+with the sale, we changed the name of Gyyr to MAXxess Systems, Inc. to reflect
+the focus of the business on electronic access control systems.
+All references to our subsidiaries in this report include the prior
+business and results of operations of such subsidiaries as our business units
+prior to their incorporation.
+During the quarter ended December 31, 2000, we began a restructuring to
+reduce our overall expenses and to focus our business on those areas that we
+believe would provide the highest return for stockholder capital. This
+restructuring resulted in a 25% reduction in our workforce in the fiscal year
+ended March 31, 2001 and the discontinuation of certain product lines. The
+restructuring efforts in fiscal 2001 also resulted in restructuring charges of
+approximately $6.3 million for severance costs and the write down of certain
+assets. In September 2001, in connection with continued cost control efforts and
+the slowdown in the telecommunications industry, our Board of Directors approved
+the immediate discontinuation of Mariner Networks, Inc., our wholly owned
+subsidiary. Mariner had previously been included within our telecom products
+segment. The aggregate losses recognized to exit the Mariner operations were
+approximately $8.4 million and are included in the loss from discontinued
+operations in the consolidated statements of operations in the fiscal year ended
+March 31, 2002.
+As a result of the sale of the Gyyr CCTV Products division and the
+discontinuation of Mariner Networks, we reorganized our European operations and
+reduced our corporate staff. The reorganization of the European operations
+included the discontinuation of our Odetics Europe Ltd., Gyyr Europe Ltd.,
+Mariner France and Mariner Europe Ltd. operations, and the transition of our
+Broadcast and MAXxess international operations to branch office operations with
+the intent of lowering our international costs. Related to the actions in
+Europe, we incurred severance and other costs totaling $1.4 million in the
+fiscal year ended March 31, 2002.
+Critical Accounting Policies And Estimates
+Management's Discussion and Analysis of Financial Condition and Results of
+Operations is based on our consolidated financial statements included herein,
+which have been prepared in accordance with accounting principles generally
+accepted in the United States. The preparation of these financial statements
+requires management to make estimates and assumptions that affect the reported
+amounts of assets and liabilities and related disclosure of contingent assets
+and liabilities at the date of the financial statements and the reported amounts
+of revenues and expenses during the reporting period. On an ongoing basis, we
+evaluate these estimates and assumptions, including those related to the
+collectibility of accounts receivables, the valuation of inventories, the
+recoverability of long-lived assets, including goodwill, and reserves for
+restructuring and related activities. We base these estimates on historical
+experience and on various other factors which we believe to be reasonable under
+the circumstances, the results of which form the basis for making judgments
+about the carrying values of assets and liabilities that are not readily
+apparent from other sources. These estimates and assumptions by their nature
+involve risks and uncertainties, and may prove to be inaccurate. In the event
+that any of our estimates or assumptions are inaccurate in any material respect,
+it could have a material adverse effect on our reported amounts of assets and
+liabilities at the date of the financial statements and the reported amounts of
+revenues and expenses during the reporting period.
+18
+The following critical accounting policies affect our more significant
+judgments and estimates used in the preparation of our consolidated financial
+statements.
+Revenue Recognition. We record product revenues and related cost of sales
+on the date of shipment or, if required, upon acceptance by the customer,
+provided that we believe collectibility of the net sales amount is probable.
+Accordingly, at the date revenue is recognized, the significant uncertainties
+concerning the sale have been resolved. Unless otherwise stated in our product
+literature, we provide a one to two year warranty on all product material and
+workmanship, and establish reserves for potential warranty returns as products
+are shipped. Defective products will be either repaired or replaced, at our
+option, upon meeting certain criteria.
+Contract revenue is derived primarily from long-term contracts with
+governmental agencies. Contract revenue includes costs incurred plus a portion
+of estimated fees or profits determined on the percentage of completion method
+of accounting based on the relationship of costs incurred to total estimated
+costs. We record a charge to earnings for any anticipated losses on contracts in
+the period in which such losses are identified. Changes in job performance and
+estimated profitability, including those arising from contract penalty
+provisions and final contract settlements, may result in revisions to cost and
+revenue and are recognized in the period in which the revisions are determined.
+We include in revenue profit incentives in the period in which their realization
+is reasonably assured.
+We sell certain products that include software which is integral to the
+functionality of the product. When such products do not require significant
+production, modification or customization of the software, we recognize revenue
+is upon delivery, assuming the fee is fixed and collectibility is probable. If
+an arrangement requires significant production, modification or customization of
+the software, we account for the arrangement on the percentage of completion
+method of accounting as costs are incurred.
+We record revenues from follow-on service and support, for which we charge
+separately, in the period in which such services are performed. We record
+revenues from computer software maintenance agreements ratably over the term of
+the agreements. When computer software maintenance is included in a software
+license agreement, we defer an appropriate portion of the license fee and
+recognize it over the maintenance period.
+Accounts Receivable. We estimate the collectibility of customer receivables
+on an ongoing basis by periodically reviewing balances outstanding over a
+certain period of time. We have recorded reserves for receivables deemed to be
+at risk for collection as well as a general reserve based on our historical
+experience. A considerable amount of judgment is required in assessing the
+ultimate realization of these receivables, including the current
+credit-worthiness of each customer. If the financial condition of our customers
+deteriorates, resulting in an impairment of their ability to make required
+payments, additional allowances may be required which could adversely affect our
+operating results.
+Inventory. We state our inventories at the lower of cost or market and
+provide reserves for potentially excess and obsolete inventory. In assessing the
+ultimate realization of inventories, we make judgments as to future demand
+requirements and compare that with the current or committed inventory levels.
+Reserves are established for inventory levels that exceed future demand. It is
+possible that reserves over and above those already established may be required
+in the future if market conditions for our products should deteriorate.
+Impairment of Assets and Restructuring. We assess the impairment of
+goodwill and other identifiable intangibles whenever events or changes in
+circumstances indicate that the carrying value may not be recoverable. The
+determination of related estimated useful lives and whether or not these assets
+are impaired involves significant judgments, related primarily to the future
+profitability and/or future value of the assets. Changes in our strategic plan
+and/or market conditions could significantly impact these judgments and require
+adjustments to recorded asset balances.
+In 2001, the FASB issued Statement No. 142, Goodwill and Other Intangible
+Assets ("Statement 142"), which we adopted on April 1, 2002. Under Statement
+142, goodwill will be subject to annual impairment tests based upon a comparison
+of the fair value of each of our reporting units, as defined, and the carrying
+value of the reporting units' net assets, including goodwill. Pursuant to
+Statement 142, we are currently testing our goodwill for impairment, and are
+unable at this time to estimate the amount of the impairment charge, if any,
+that may be required.
+19
+During fiscal 2002, we recorded reserves in connection with the
+discontinuance of out Mariner Networks subsidiary, the sale of the assets of our
+Gyyr CCTV Products division and the restructuring of our European operations.
+These reserves include estimates pertaining to employee separation costs and
+facility closure costs. Although we do not anticipate significant changes, the
+actual costs to settle such liabilities may differ from the amounts estimated.
+Results of Operations
+The following table sets forth certain income statement data as a
+percentage of total net sales and contract revenues for the periods indicated
+and should be read in conjunction with Management's Discussion and Analysis of
+Financial Condition and Results of Operations.
+As of March 31,
+---------------
+2000 2001 2002
+---- ---- ----
+Net sales ............................................................... 76.3% 73.7% 61.6%
+Contract revenues ....................................................... 23.7 26.3 38.4
+------ ------ -------
+Total net sales and contract revenues ................................... 100.0% 100.0% 100.0%
+Gross profit--net sales ................................................. 18.0 20.0 39.3
+Gross profit--contract revenues ......................................... 28.0 31.2 42.5
+Selling, general and administrative expense ............................. 45.7 46.5 41.3
+Research and development expense ........................................ 16.5 18.1 13.6
+Special charge .......................................................... -- 8.3 3.7
+------ ------ -------
+Loss from operations .................................................... (41.8) (49.8) (18.1)
+Non-operating income (expense):
+Royalty/other income ............................................... 48.9 25.0 4.8
+Interest expense, net .............................................. (2.6) (2.3) (7.0)
+Income taxes (benefit) .................................................. -- -- (1.3)
+Minority interest in earnings of subsidiary ............................. -- -- 3.2
+Income and (loss) from discontinued operations, net of income taxes ..... (7.4) (15.6) (21.7)
+Extraordinary loss from early extinguishment of debt .................... -- -- (0.8)
+------ ------ -------
+Net loss ................................................................ (2.9)% (42.7)% (44.7)%
+====== ====== =======
+Net Sales and Contract Revenues. Net sales and contract revenues consist of
+(i) sales of products and services to commercial and municipal agencies ("net
+sales") and (ii) revenues derived from contracts with state, county and
+municipal agencies for ITS projects ("contract revenues"). Contract revenues
+also include revenue from contracts with agencies of the United States
+government and foreign entities for space-borne recorders. Total net sales and
+contract revenues decreased 21.9% to $59.5 million for the fiscal year ended
+March 31, 2002 ("fiscal 2002") compared to $76.2 million for the fiscal year
+ended March 31, 2001 ("fiscal 2001"), and decreased 3.1% for the fiscal year
+ended March 31, 2001 compared to $78.6 million for the fiscal year ended March
+31, 2000 ("fiscal 2000").
+Net Sales. Net sales decreased 34.7% to $36.6 million in fiscal 2002
+compared to $56.1 million in fiscal 2001. The majority of the decrease in net
+sales in fiscal 2002 compared to fiscal 2001 was attributable to our sale of the
+Gyyr CCTV Products division ("CCTV") late in the second quarter of fiscal 2002.
+CCTV product sales in fiscal 2002 include sales only through the date of the
+divestiture. CCTV product sales comprised $26.4 million and $8.3 million of net
+sales in fiscal 2001 and fiscal 2002, respectively. The Company also experienced
+decreased sales in Broadcast, Zyfer and MAXxess, which were offset by increased
+sales of Iteris products in fiscal 2002 compared to fiscal 2001. Iteris sales
+growth reflects increased unit sales of Vantage video detection systems and
+AutoVue lane departure warning systems. In the third quarter of fiscal 2001,
+Broadcast determined it would not pursue continued sales opportunities for its
+Roswell facility management system and shifted the focus of its business to
+sales of its AIRO Automation systems. The average selling price of an AIRO
+system is lower than that of Broadcast's tape library products that comprised a
+significant portion of its net sales in the prior fiscal year. The decrease in
+Broadcast net sales largely reflects sales of a more focused, software centric
+product line in fiscal 2002 compared to fiscal 2001. The decrease in Zyfer sales
+in fiscal 2002 primarily reflects its transition to selling its new line of
+CommSynch II products that address specialized communications applications, and
+the decline in revenue derived from LGIC, a significant Korean-based customer.
+The decrease in MAXxess net sales primarily reflects the decrease in sales to a
+major telecommunications customer in fiscal 2002 compared to fiscal 2001.
+20
+Net sales decreased 6.4% to $56.1 million in fiscal 2001 compared to $59.9
+million in fiscal 2000 as a result of declining sales in Broadcast and MAXxess,
+offset in part by increased sales in Iteris and Zyfer. Broadcast sales decreased
+20.1% in fiscal 2001 compared to fiscal 2000 as a result of declining unit sales
+of its automated tape libraries. In the third quarter of fiscal 2001, Broadcast
+determined it would not pursue continued sales opportunities for its Roswell
+facility management system and shifted the focus of its business on sales of its
+AIRO Automation Systems. MAXxess' sales decreased 10.8% in fiscal 2001 compared
+to fiscal 2000 due principally to the decline in sales of analog based
+time-lapse recorder product families. During the first quarter of fiscal 2001,
+MAXxess' divested its Vortex Dome and Quarterback Controller product lines as
+part of a broader strategy to narrow its product offering to digital and analog
+recording and access control systems. Iteris' product sales increased 37% in
+fiscal 2001, primarily due to increased unit sales of its Vantage video
+detection products.
+Contract Revenues. Contract revenues increased 14.0% to $22.8 million in
+fiscal 2002 compared to $20.0 million in fiscal 2001, and increased 7.4%
+compared to $18.7 million in fiscal 2000. The increase in contract revenues in
+both fiscal 2002 and fiscal 2001 reflects an increase in Iteris' contract
+revenues for ITS projects.
+Contract revenues derived from Iteris represented 88.4% of total contract
+revenues in fiscal 2002 compared to 87.0% of total contract revenues in fiscal
+2001, and 83.5% of total contract revenues in fiscal 2000. The increase in
+Iteris' contract revenues in both fiscal 2002 and fiscal 2001 was offset in part
+by continued declines in contract revenues derived from the sale of space-borne
+recorders and related service and equipment to agencies of the United States
+Government.
+Gross Profit. Total gross profit increased 37.7% to $24.1 million in fiscal
+2002 compared to $17.5 million in fiscal 2001, and increased 9.2% in fiscal 2001
+compared to $16.0 million in fiscal 2000. Total gross profit as a percent of net
+sales and contract revenues increased to 40.1% in fiscal 2002 compared to 23.0%
+in fiscal 2001 and 20.4% in fiscal 2000. Gross profit as a percentage of net
+sales increased to 39.3% in fiscal 2002 compared to 20.0% in fiscal 2001 and
+18.0% in fiscal 2000. Gross profit in fiscal 2001 was net of charges of $3.1
+million for the write-off of inventories associated with discontinued product
+lines. Before the effect of these write-offs, gross profit as percent net sales
+in fiscal 2001 was 25.6%.
+The increase in gross profit in fiscal 2002 compared to fiscal 2001
+primarily reflects increased gross margin on net sales in Iteris and Broadcast.
+Broadcast experienced an improved gross margin as a result of its focus on the
+sale of higher margin AIRO Automation Systems, and fewer sales of automated tape
+libraries, which historically had low gross profits relative to sales. Iteris'
+gross profits improved in fiscal 2002 primarily as a result of a 53.5% increase
+in Vantage sales and related improved manufacturing efficiencies. The increase
+in gross profit in fiscal 2002 also reflects the benefit of the divestiture of
+the Gyyr CCTV Product line, which had historically low gross margins relative to
+net sales in fiscal 2001.
+The increase in gross profit as a percent of net sales in fiscal 2001
+reflects increased gross profit on sales of Iteris Vantage products, which
+comprised 17.5% of net sales in fiscal 2001 compared to 11.7% of net sales in
+fiscal 2000. The improvement in Vantage gross profits was offset in part by
+pricing concessions given to certain customers in our Broadcast business, which
+negatively impacted the gross profit performance in fiscal 2000. During fiscal
+2000, gross profit on net sales was also impaired due to our adjustments to
+inventory reserves and capitalized software related to certain discontinued
+products and product options in Broadcast and MAXxess.
+Gross profit as a percent of contract revenues increased to 57.5% in fiscal
+2002 compared to 31.2% in fiscal 2001, and compared to 28.0% in fiscal 2000. The
+increase in gross profit on contract revenues in fiscal 2002 principally
+reflects adjustments to loss reserves on certain long term contracts in Iteris
+resulting from changes in the scope of work defined by a major customer. The
+increase in gross profit on contract revenues in fiscal 2001 primarily reflects
+improved gross profit performance in both Iteris and Zyfer. We recognize
+contract revenues and related gross profit using percentage of completion
+contract accounting, and the underlying mix of contract activity primarily
+affects the related gross profit recognized in any given year.
+Selling, General and Administrative Expense. Selling, general and
+administrative expense decreased 30.6% to $24.6 million (or 41.3% of total net
+sales and contract revenues) in fiscal 2002 compared to $35.4 million (or 46.5%
+of total net sales and contract revenues) in fiscal 2001, and decreased 1.5% in
+fiscal 2001 compared to $35.9 million (or 45.7% of total net sales and contract
+revenues) in fiscal 2000. The restructuring activities, which commenced during
+the third quarter of fiscal 2001, resulted in substantial decreases in selling,
+general and administrative
+21
+expense in Broadcast, MAXxess and Iteris in fiscal 2002. The expense reductions
+in the current fiscal year that are associated with the restructuring were
+augmented by further cost reductions associated with the divestiture of the Gyyr
+CCTV Product line in September 2001.
+The decrease in selling, general and administrative expenses in fiscal 2001
+reflects increased expenses in Iteris, offset by decreased expenses in MAXxess
+and Broadcast. During fiscal 2001, Iteris experienced increased general and
+administrative expense related to the build-up of its administrative
+infrastructure to support its planned initial public offering and spin-off from
+Odetics, originally planned for the first quarter of fiscal 2001. As a result of
+the aborted public offering and spin-off, general and administrative expense in
+fiscal 2001 included a charge of approximately $360,000 related to the write-off
+of deferred public offering costs. The increase in Iteris was offset by
+decreased expenditures in MAXxess and Broadcast, realized as part of cost
+reductions included in our restructuring activities.
+Research and Development Expense. Research and development expense
+decreased 41.0% to $8.1 million (or 13.6% of total net sales and contract
+revenues) in fiscal 2002 compared $13.8 million (or 18.1% of total net sales and
+contract revenues) in fiscal 2001, and increased 6.0% in fiscal 2001 compared to
+$13.0 million (or 16.5% of total net sales and contract revenues) in fiscal
+2000. For competitive reasons, we closely guard the confidentiality of specific
+development projects. The decrease in research and development expense in fiscal
+2002 reflects the full fiscal year cost benefit of the restructuring, which was
+begun in the fourth quarter of fiscal 2001. The restructuring resulted in
+substantial decreases in research and development expenditures, primarily in the
+areas of payroll and related benefits, prototype material cost and consulting
+fees. Reductions in research and development expenses in fiscal 2002 were also
+associated with the divestiture of the Gyyr CCTV Product line at the end of the
+second quarter of fiscal 2002.
+The increase in research and development expense in fiscal 2001 reflects
+increased spending primarily by Iteris, partially offset by reductions in
+spending by Gyyr and Broadcast. The increase in Iteris research and development
+expense largely represents expenditures to support its development initiatives
+for its Personalized Traveler Information Systems and, to a lesser extent,
+continued development of its AutoVue product offering. As part of cost reduction
+initiatives completed in the third quarter of fiscal 2001, Iteris substantially
+reduced spending to support development of its Personalized Traveler Information
+Systems. The reductions in research and development expense in MAXxess and
+Broadcast reflect the result of our overall expense reduction efforts.
+Special Charge. The special charge of $2.2 million in fiscal 2002 reflects
+approximately $700,000 in severance charges incurred upon the retirement of the
+former Chief Executive Officer of Odetics, and charges of $1.5 million related
+to the reorganization of our European operations. The reorganization of European
+operations included the discontinuation of our Odetics Europe Ltd., Gyyr Europe
+Ltd., Mariner France and Mariner Europe Ltd. operations, and the transition of
+our Broadcast and MAXxess international operations to branch office operations
+with the intent of lowering our international costs.
+In fiscal 2001, we incurred restructuring charges of $6.3 million.
+Approximately $1.3 million of the charges related to severance payments for
+staffing reductions, and the remainder represents non-cash charges for asset
+write-downs and reserves established in connection with the discontinuation of
+certain product lines.
+Royalty Income. During fiscal 2000 and 2001, in connection with the
+settlement of patent litigation filed that Odetics filed against StorageTek, we
+received proceeds, net of expenses and fees, of approximately $38.4 million and
+$17.8 million respectively in full settlement of the amounts due us.
+Interest Expense, Net. Interest expense, net reflects the net of interest
+expense and interest income as follows:
+Year Ended March 31,
+-----------------------------------
+2000 2001 2002
+--------- --------- ---------
+Interest expense ................. $2,313 $2,012 $4,190
+Interest income .................. 265 250 --
+------ ------ ------
+Interest expense, net ............ $2,048 $1,762 $4,190
+Interest expense increased 108.3% in fiscal 2002 compared to fiscal 2001
+and decreased 13.0% in fiscal 2001 compared to fiscal 2000. The increase in
+interest expense in fiscal 2002 reflects an increase in our average outstanding
+borrowings, an increase in our cost of borrowing and $1.2 million of
+amortization of debt discount associated with a warrant issued in connection
+with certain of our financing transactions. Interest income in fiscal 2000 and
+fiscal 2001 and
+22
+the decline in interest expense from 2000 to fiscal 2001 is primarily related to
+interest earned on invested cash received from our settlement with StorageTek.
+Extraordinary Item. The extraordinary loss incurred in fiscal 2002 relates
+to a prepayment penalty on the retirement of our mortgage note payable resulting
+from the refinancing of our Anaheim real property.
+Income Taxes. During fiscal 2002, we recognized an income tax benefit of
+$785,000 for the recovery of net operating loss carrybacks made available under
+the Job Creation and Workers Association Act of 2002. We have not provided
+income tax benefit for the losses incurred in fiscal 2000 and fiscal 2001 due to
+the uncertainty as to the ultimate realization of the related benefit.
+Liquidity and Capital Resources
+As of March 31, 2002, we had cash and cash equivalents of $408,000. During
+fiscal 2002, we used $18.2 million of cash to fund our operations, which
+reflects our net loss of $26.6 million reduced by non-cash charges of $8.4
+million related to asset impairment write-downs and reserves for costs to exit
+Mariner Networks, $3.8 million for depreciation and amortization, and $1.6
+million of losses incurred from the sale of common stock of our majority owned
+subsidiary, Iteris, Inc. Significant financing and investing activities during
+fiscal 2002 are discussed below.
+In April 2001, we concluded the sale of our Vortex Dome and Quarterback
+Controller product lines for approximately $1.1 million in net cash proceeds
+resulting in a $0.1 million gain. The proceeds were used to reduce outstanding
+borrowings due on our bank line of credit.
+In May 2001, we received $16.0 million pursuant to a promissory note
+secured by a first trust deed on our principal facilities in Anaheim, California
+which bore interest at 10% per annum. This promissory note was paid in full at
+its scheduled maturity date on May 29, 2002. In connection with this note, we
+issued warrants to the lender to purchase 426,667 shares of our Class A common
+stock at an exercise price of $4.00 per share. In connection with a forbearance
+agreement negotiated in November 2001, we repriced the exercise price of these
+warrants to $3.00 per share. We allocated approximately $1.3 million of the loan
+proceeds to the warrant, and will accrete that amount to interest expense over
+the term of the loan.
+Of the $16.0 million proceeds received from this note, we used
+approximately $6.0 million to retire the pre-existing first trust deed on our
+Anaheim real property, which included a prepayment penalty of $450,000. This
+prepayment penalty is reflected as an extraordinary item in the accompanying
+consolidated statement of operations. We also used approximately $5.9 million of
+the proceeds to repay all outstanding borrowings under our bank line of credit,
+which was then terminated. We used the balance of the proceeds from this
+financing, after payment of the related expenses, for general working capital
+purposes.
+In August 2001, Iteris issued 1,781,268 shares of its Series A preferred
+stock to one institutional investor for a purchase price of $5.0 million in
+cash. In addition, Iteris issued 1,343,645 shares of its Series A preferred
+stock and 547,893 shares of its common stock in exchange for $500,000 in cash
+and the retirement of its $3.75 million subordinated convertible promissory
+note, which Iteris entered into in January 2000, plus related accrued interest
+of $400,000. In August and December 2001, Odetics sold 1,539,241 shares of
+Iteris common stock that Odetics owned for proceeds of 3.8 million to a group of
+investors, which included certain members of management of Odetics and Iteris.
+As a result of this transaction, we realized a loss of $0.6 million. At December
+31, 2001, Odetics owned 78.2% of the outstanding common stock of Iteris or 62.7%
+as calculated for the preferred stock conversion equivalent.
+In August 2001, Iteris entered into a loan and security agreement which
+provided for a line of credit with maximum borrowings of $5.0 million. The line
+of credit bears interest at prime plus 2% (6.75% at March 31, 2002) and matures
+in August 2004. At March 31, 2002, $0.8 million was outstanding under the line
+of credit and $3.3 million was available for future borrowing.
+In September 2001, we completed the sale of substantially all of the assets
+of our Gyyr CCTV Products division for $8.8 million in cash, plus the assumption
+of $1.0 million in debt. In connection with this transaction, we recorded a
+non-operating gain of $2.5 million in the three months ended September 30, 2001.
+We used the proceeds from the transaction to retire the remaining obligations
+due under our previous bank
+23
+line of credit, which has now expired, and to fund severance obligations and for
+other general working capital requirements.
+In September 2001, we discontinued the operations of our wholly-owned
+subsidiary, Mariner Networks Inc. The aggregate losses recognized to exit the
+Mariner operations were approximately $8.4 million, and are included in the loss
+from discontinued operations in our consolidated statements of operations for
+fiscal 2002.
+In February 2002, we entered into a $1.25 million line of credit with a
+partnership controlled by the Chairman of our Board of Directors. The line of
+credit bears interest at prime plus 4% (8.75% at March 31, 2002) and matures in
+July 2003. At March 31, 2002, $1.25 million was outstanding under this line of
+credit.
+In May 2002, we completed the sale and leaseback of our Anaheim, California
+facilities for an aggregate sale price of $22.6 million. Approximately $16.4
+million of the proceeds from this sale were used to repay the outstanding
+indebtedness under the 2001 promissory note which was secured by a first deed of
+trust on our Anaheim facilities. The balance of the proceeds from this sale will
+be used for general working capital purposes.
+The Company's contractual obligations are as follows at March 31, 2002
+Payments Due by Period (in thousands)
+-------------------------------------------------------------------
+1 year After
+Total or less 2-3 years 4-5 years 5 years
+----- ------- --------- --------- -------
+Note payable ..................... 16,000 16,000 - - -
+Lines of credit .................. 2,017 - 2,017 - -
+Capital lease obligations ........ 402 377 25 - -
+Operating leases.................. 545 327 218 - -
+------ ------ ----- ----- ----
+Total ...................... 18,964 16,704 2,260 - -
+====== ====== ===== ===== ====
+The $16.0 million note payable was paid in full in May 2002, upon the
+completion of the sale and leaseback of our Anaheim facility. Under the terms of
+the lease, we committed to lease one of the two buildings on the property for a
+period of ten years, and to lease the other building for a period of 30 months.
+Minimum lease payments under the terms of these leases over the next five years,
+and thereafter are as follows: 2003: $2.1 million; 2004: $2.5 million; 2005:
+$2.3 million; 2006: $1.8 million; 2007: $1.8 million; and thereafter: $9.4
+million.
+We expect that our operations will continue to use net cash at least
+through the first half of fiscal 2003. We also expect to have an ongoing need to
+raise cash by securing additional debt or equity financing, or by divesting
+certain assets to fund our operations until we return to profitability and
+positive operating cash flows. However we cannot be certain that we will be able
+to secure additional debt or equity financing or divest of certain assets on
+terms acceptable to us, or at all. Our future cash requirements will be highly
+dependent upon our ability to control expenses, as well as the successful
+execution of the revenue plans by each of our business units. As a result, any
+projections of future cash requirements and cash flows are subject to
+substantial uncertainty.
+These conditions, together with our recurring operating losses, raise
+substantial doubt about our ability to continue as a going concern. Our
+consolidated financial statements do not include any adjustments to reflect the
+possible future effects on the recoverability and classification of assets or
+liabilities that may result from the outcome of this uncertainty.
+Recent Accounting Pronouncements
+In August 2001, the Financial Accounting Standards Board (FASB) issued
+Statement of Financial Accounting Standards No.144, "Accounting for the
+Impairment or Disposal of Long-Lived Assets" (SFAS 144). The Statement
+supersedes FASB Statement No. 121, Accounting for the Impairment of Long-Lived
+Assets and for Long-Lived Assets to be Disposed Of, however it retains the
+fundamental provisions of that statement related to the recognition and
+measurement of the impairment of long-lived assets to be "held and used." SFAS
+144 also supersedes the accounting and reporting provisions of Accounting
+Principles Board Opinion No. 30, Reporting the Results of Operation's--Reporting
+the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual
+and Infrequently Occurring Events and Transactions (APB 30), for the disposal of
+a segment of a business. Under SFAS
+24
+144 a component of a business that is held for sale is reported in discontinued
+operations if (i) the operations and cash flows will be, or have been,
+eliminated from the on-going operations of the company and, (ii) the company
+will not have any significant continuing involvement in such operations. In the
+quarter ended September 30, 2001, we adopted the provisions of SFAS 144
+effective April 1, 2001.
+In 2001, the FASB issued Statement No. 141, Business Combinations ("SFAS
+141"), and No. 142, Goodwill and Other Intangible Assets ("SFAS 142"), which we
+adopted on April 1, 2002. Under the new rules, goodwill and intangible assets
+deemed to have indefinite lives will no longer be amortized but, instead, will
+be subject to annual impairment tests. Other intangible assets will continue to
+be amortized over their useful lives. We will apply the new rules on accounting
+for goodwill and other intangible assets beginning in the first quarter of
+fiscal 2003. At March 31, 2002, we had goodwill of approximately $9.8 million.
+Pursuant to Statement 142, we are currently testing our goodwill for impairment
+and are unable at this time to estimate the amount of the impairment charge, if
+any, that may be required.
+On a pro forma basis, application of the non-amortization provision of SFAS
+141 would have reduced our net loss in the years ended March 31, 2000, 2001 and
+2002 as follows:
+Year ended March 31
+(in thousands) 2000 2001 2002
+---------------------------------------
+Pro forma net loss $(592) $(30,616) $(25,072)
+25
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.
+Our exposure to interest rate risk is limited to our lines of credit.
+Iteris' and Odetics' lines of credit bear interest at the prevailing prime rate,
+plus 2% and 4%, respectively. Our $16.0 million note payable, prior to its
+repaymentin May 2002, carried a fixed rate of interest. We estimate that, based
+on amounts outstanding at March 31, 2002, a 10% increase in the prime rate would
+result in an increase in interest expense, on an annualized basis, of less than
+$0.1 million.
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
+The financial statements and supplementary data required by Regulation S-X
+are included in this Form 10-K commencing on page F-1.
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
+FINANCIAL DISCLOSURE.
+Not applicable.
+26
+PART III
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
+Directors and Executive Officers
+(a) Indemnification of Directors. The information under the caption
+"Election of Directors" appearing in our proxy statement, is incorporated herein
+by reference.
+(b) Identification of Executive Officers. The information under the caption
+"Executive Compensation and Other Information" appearing in our proxy statement,
+is incorporated herein by reference.
+(c) Compliance with Section 16(a) of the Exchange Act. The information
+under the caption "Executive Compensation and Other Information" appearing in
+our proxy statement, is incorporated herein by reference.
+ITEM 11. EXECUTIVE COMPENSATION
+The information under the caption "Executive Compensation and Other
+Information" appearing in our proxy statement, is incorporated herein by
+reference.
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
+RELATED STOCKHOLDER MATTERS
+As of March 31, 2002, Odetics had only one plan, the 1997 Stock Incentive
+Plan, pursuant to which equity securities of Odetics are authorized for
+issuance. The following table sets forth certain information regarding this
+plan:
+(a) (b) (c)
+Number of Securities
+Number of Securities Remaining Available
+to be Issued Weighted Average under Equity Compensation
+Upon Exercise of Exercise Price of Plans (excluding some
+Equity Compensation Plans Outstanding Options, Outstanding Options, securities reflected
+Approved by Security Holders Warrants and Rights Warrants and Rights in column (a))
+---------------------------- -------------------- -------------------- -------------------------
+1997 Stock Incentive Plan.... 328,655 8.37 1,322,195
+Equity Compensation Plans Not
+Approved by Security Holders
+----------------------------
+None......................... - - -
+Total..........................
+The information under the caption "Principal Stockholders and Common Stock
+Ownership of Certain Beneficial Owners and Management," appearing in our proxy
+statement, is incorporated herein by reference.
+ITEM 13. CERTAIN TRANSACTIONS
+The information under the caption "Certain Transactions," appearing in our
+proxy statement, is incorporated herein by reference.
+PART IV
+ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
+(a) Documents filed as part of this report:
+1. Financial Statements. The following financial statements of Odetics are
+included in a separate section of this Annual Report on Form 10-K commencing on
+the pages referenced below:
+Page
+----
+Report of Independent Auditors ....................................................................... F-2
+Consolidated Balance Sheets as of March 31, 2001 and 2002 ............................................ F-3
+Consolidated Statements of Operations for the years ended March 31, 2000, 2001 and 2002 .............. F-4
+Consolidated Statements of Stockholders' Equity for the years ended March 31, 2000, 2001
+and 2002 ........................................................................................... F-5
+Consolidated Statements of Cash Flows for the years ended March 31, 2000, 2001 and 2002 .............. F-6
+Notes to Consolidated Financial Statements ........................................................... F-7
+2. Financial Statement Schedules.
+Schedule II-- Valuation and Qualifying Accounts ...................................................... S-1
+27
+All other schedules have been omitted because they are not required or the
+required information is included in our consolidated financial statements and
+notes thereto.
+3. (a) Exhibits.
+3.1 Certificate of Incorporation of Odetics, as amended (incorporated by
+reference to Exhibit 19.2 to Odetics' Quarterly Report on Form 10-Q
+for the quarter ended September 30, 1987).
+3.2 Bylaws of Odetics, as amended (incorporated by reference to Exhibit
+4.2 to Odetics' Registration Statement on Form S-1 (Reg. No.
+033-67932) as filed with the SEC on July 6, 1993).
+4.1 Specimen of Class A common stock and Class B common stock certificates
+(incorporated by reference to Exhibit 4.3 to Amendment No. 1 to
+Odetics' Registration Statement on Form S-1 (Reg. No. 033-67932) as
+filed with the SEC on September 30, 1993).
+4.2 Form of rights certificate for Odetics' preferred stock purchase
+rights (incorporated by reference to Exhibit A of Exhibit 4 to
+Odetics' Current Report on Form 8-K as filed with the SEC on May 1,
+1998).
+10.1 Profit Sharing Plan and Trust (incorporated by reference to Exhibit
+10.3 to Odetics' Amendment No. 2 to the Registration Statement on Form
+S-8 (Reg. No. 002-98656) as filed with the SEC on May 5, 1988).
+10.2 Form of Executive Deferral Plan between Odetics and certain employees
+of Odetics (incorporated by reference to Exhibit 10.4 to Odetics'
+Annual Report on Form 10-K for the year ended March 31, 1988).
+10.3 Form of Indemnity Agreement entered into by Odetics and certain of its
+officers and directors (incorporated by reference to Exhibit 19.4 to
+Odetics' Quarterly Report on Form 10-Q for the quarter ended September
+30, 1988).
+10.4 Amendment Nos. 3 and 4 to the Profit Sharing Plan and Trust
+(incorporated by reference to Exhibits 4.3.1 and 4.3.2, respectively,
+to Amendment No. 3 to Odetics' Registration Statement on Form S-3
+(Reg. No. 002-86220) as filed with the SEC on June 13, 1990).
+10.5 1997 Stock Incentive Plan of Odetics (incorporated by reference to
+Exhibit 99.1 to Odetics' Registration Statement on Form S-8 (File No.
+333-30396) as filed with the SEC on February 14, 2000).
+10.6 Form of Notice of Grant of Stock Option (incorporated by reference to
+Exhibit 99.2 to Odetics' Registration Statement on Form S-8 (File No.
+333-30396) as filed with the SEC on February 14, 2000)
+10.7 Form of Stock Option Agreement (incorporated by reference to Exhibit
+99.3 to Odetics' Registration Statement on Form S-8 (File No.
+333-30396) as filed with the SEC on February 14, 2000).
+10.8 Form of Addendum to Stock Option Agreement--Involuntary Termination
+Following Corporate Transaction or Change in Control (incorporated by
+reference to Exhibit 99.4 to Odetics' Registration Statement on Form
+S-8 (File No. 333-30396) as filed with the SEC on February 14, 2000).
+10.9 Form of Addendum to Stock Option Agreement--Limited Stock Appreciation
+Rights (incorporated by reference to Exhibit 99.5 to Odetics'
+Registration Statement on Form S-8 (File No. 333-30396) as filed with
+the SEC on February 14, 2000).
+10.10 Form of Stock Issuance Agreement (incorporated by reference to Exhibit
+99.6 to Odetics' Registration Statement on Form S-8 (File No.
+333-30396) as filed with the SEC on February 14, 2000)
+28
+10.11 Form of Addendum to Stock Issuance Agreement--Involuntary Termination
+Following Corporate Transaction/Change in Control (incorporated by
+reference to Exhibit 99.7 to Odetics' Registration Statement on Form
+S-8 (File No. 333-30396) as filed with the SEC on February 14, 2000).
+10.12 Form of Notice of Grant of Automatic Stock Option--Initial Grant filed
+as Exhibit 99.8 filed as Exhibit (incorporated by reference to Exhibit
+99.8 to Odetics' Registration Statement on Form S-8 (File No.
+333-30396) as filed with the SEC on February 14, 2000).
+10.13 Form of Notice of Grant of Automatic Stock Option--Annual Grant
+(incorporated by reference to Exhibit 99.9 to Odetics' Registration
+Statement on Form S-8 (File No. 333-30396) as filed with the SEC on
+February 14, 2000).
+10.14 Form of Automatic Stock Option Agreement filed as Exhibit 99.10 to the
+(incorporated by reference to Exhibit 99.10 to Odetics' Registration
+Statement on Form S-8 (File No. 333-30396) as filed with the SEC on
+February 19, 2000).
+10.15 Rights Agreement dated April 24, 1998 between Odetics and BankBoston,
+N.A., which includes the form of Certificate of Designation for the
+junior participating preferred stock as Exhibit A, the form of rights
+certificate as Exhibit B and the summary of rights to purchase Series
+A preferred shares as Exhibit C (incorporated by reference to Exhibit
+4 to Odetics' Current Report on Form 8-K as filed with the SEC on May
+1, 1998).
+10.16 1994 Long-Term Equity Plan of Odetics (incorporated by reference to
+Exhibit 4.3 to Odetics' Registration Statement on Form S-8 (File No.
+333-05735) as filed with the SEC on June 11, 1996).
+10.17 Subordinated Convertible Note Purchase Agreement dated January 25,
+2000 between Iteris, Inc. and DaimlerChrysler GmbH (incorporated by
+reference to Exhibit 10.31 to Odetics' Annual Report on Form 10-K as
+filed with the SEC on June 29, 2000).
+10.18 Subordinated Convertible Note dated January 25, 2000 between Iteris,
+Inc. and DaimlerChrysler GmbH (incorporated by reference to Exhibit
+10.32 to Odetics' Annual Report on Form 10-K as filed with the SEC on
+June 29, 2000).
+10.19 Amendment to Rights Agreement, dated May 21, 2001, by and between
+Odetics and Fleet National Bank (a.k.a. Bank Boston, N.A.)
+(incorporated by reference to Exhibit 99.4 to Odetics' Current Report
+on Form 8-K as filed with the SEC on June 1, 2001).
+10.20 Amended and Restated Agreement of Purchase and Sale and Escrow
+Instructions, dated February 19, 2002, by and between Odetics, Inc.
+and 1515 South Manchester, LLC (incorporated by reference to Exhibit
+2.1 to Odetics' Current Report on Form 8-K as filed with the SEC on
+June 12, 2002).
+21 Subsidiaries of Odetics.
+23.1 Consent of Independent Auditors.
+(b) Reports on Form 8-K
+On June 12, 2002, we filed a Current Report on Form 8-K to announce the
+sale and lease back of our headquarters and principal operating facilities in
+Anaheim, California.
+29
+SIGNATURES
+Pursuant to the requirements of Section 13 or 15(d) of the Securities
+Exchange Act of 1934, the Registrant has duly caused this Report to be signed on
+its behalf by the undersigned, thereunto duly authorized, in the City of
+Anaheim, State of California, on June 28, 2002.
+ODETICS, INC.
+By: /s/ GREGORY A. MINER
+--------------------------------
+Gregory A. Miner,
+Chief Executive Officer
+and Chief Financial Officer
+POWER OF ATTORNEY
+We, the undersigned officers and directors of Odetics, Inc., do hereby
+constitute and appoint Gary Smith and Gregory A. Miner, and each of them, our
+true and lawful attorneys-in-fact and agents, each with full power of
+substitution and resubstitution, for him and in his name, place and stead, in
+any and all capacities, to sign any and all amendments to this report, and to
+file the same, with exhibits thereto, and other documents in connection
+therewith, with the Securities and Exchange Commission, granting unto said
+attorneys-in-fact and agents, and each of them, full power and authority to do
+and perform each and every act and thing requisite or necessary to be done in
+and about the premises, as fully to all intents and purposes as he might or
+could do in person, hereby, ratifying and confirming all that each of said
+attorneys-in-fact and agents, or his substitute or substitutes, may lawfully do
+or cause to be done by virtue hereof.
+Pursuant to the requirements of the Securities Exchange Act of 1934, this
+report has been signed below by the following persons in the capacities and on
+the dates indicated:
+Signature Title Date
+--------- ----- ----
+/s/ GREGORY A. MINER Director, Chief Executive Officer June 28, 2002
+--------------------
+Gregory A. Miner and Chief Financial Officer
+(principal executive officer and
+principal financial officer)
+/s/ JOEL SLUTZKY Chairman of the Board June 28, 2002
+-----------------
+Joel Slutzky
+/s/ KEVIN C. DALY Director June 28, 2002
+------------------
+Kevin C. Daly, Ph.D
+/s/ CRANDALL GUDMUNDSON Director June 28, 2002
+-----------------------
+Crandall Gudmundson
+/s/ JERRY MUENCH Director June 28, 2002
+----------------
+Jerry Muench
+30
+Signature Title Date
+--------- ----- ----
+/s/ JOHN SEAZHOLTZ Director June 28, 2002
+-------------------
+John Seazholtz
+/s/ GARY SMITH Vice President and Controller June 28, 2002
+---------------
+Gary Smith (principal accounting officer)
+/s/ THOMAS L. THOMAS Director June 28, 2002
+--------------------
+Thomas L. Thomas
+/s/ PAUL E. WRIGHT Director June 28, 2002
+-------------------
+Paul E. Wright
+31
+Odetics, Inc.
+Index to Consolidated Financial Statements
+Page
+Report of Independent Auditors ..................................................................... F-2
+Consolidated Balance Sheets as of March 31, 2001 and 2002 .......................................... F-3
+Consolidated Statements of Operations for the years ended
+March 31, 2000, 2001 and 2002 .................................................................. F-5
+Consolidated Statements of Stockholders' Equity for the years ended
+March 31, 2000, 2001 and 2002 .................................................................. F-6
+Consolidated Statements of Cash Flows for the years ended
+March 31, 2000, 2001 and 2002 .................................................................. F-7
+Notes to Consolidated Financial Statements ......................................................... F-8
+F-1
+Report of Independent Auditors
+Stockholders and Board of Directors
+Odetics, Inc.
+We have audited the accompanying consolidated balance sheets of Odetics, Inc. as
+of March 31, 2001 and 2002, and the related consolidated statements of
+operations, stockholders' equity, and cash flows for each of the three years in
+the period ended March 31, 2002. Our audits also included the financial
+statement schedule listed in Item 14(a). These financial statements and schedule
+are the responsibility of the Company's management. Our responsibility is to
+express an opinion on these financial statements based on our audits.
+We conducted our audits in accordance with auditing standards generally accepted
+in the United States. Those standards require that we plan and perform the audit
+to obtain reasonable assurance about whether the financial statements are free
+of material misstatement. An audit includes examining, on a test basis, evidence
+supporting the amounts and disclosures in the financial statements. An audit
+also includes assessing the accounting principles used and significant estimates
+made by management, as well as evaluating the overall financial statement
+presentation. We believe that our audits provide a reasonable basis for our
+opinion.
+In our opinion, the consolidated financial statements referred to above present
+fairly, in all material respects, the consolidated financial position of
+Odetics, Inc. at March 31, 2001 and 2002, and the consolidated results of its
+operations and its cash flows for each of the three years in the period ended
+March 31, 2002, in conformity with accounting principles generally accepted in
+the United States. Also, in our opinion, the related financial statement
+schedule, when considered in relation to the basic financial statements taken as
+a whole, presents fairly in all material respects the information set forth
+therein.
+The accompanying consolidated financial statements have been prepared assuming
+the Company will continue as a going concern. As discussed in Note 1 to the
+consolidated financial statements, the Company's recurring losses from
+operations raise substantial doubt about its ability to continue as a going
+concern. Management's plans as to these matters are also described in Note 1.
+The consolidated financial statements do not include any adjustments that might
+result from the outcome of this uncertainty.
+/s/ Ernst & Young LLP
+Orange County, California
+May 22, 2002, except for Note 1,
+as to which the date is May 29, 2002
+F-2
+Odetics, Inc.
+Consolidated Balance Sheets
+(In thousands, except share and per share amounts)
+March 31
+2001 2002
+--------------------------
+Assets
+Current assets:
+Cash and cash equivalents $ 2,218 $ 408
+Trade accounts receivable, net of allowance for doubtful accounts of
+$1,644 in 2001 and $381 in 2002 14,300 10,301
+Costs and estimated earnings in excess of billings on uncompleted
+contracts 3,296 3,565
+Inventories:
+Finished goods 1,611 1,034
+Work in process 51 103
+Materials and supplies 8,991 7,275
+Prepaid expenses and other 992 1,830
+Assets of discontinued operations 5,639 205
+--------------------------
+Total current assets 37,098 24,721
+Property, plant and equipment:
+Land 2,060 2,060
+Buildings and improvements 18,982 19,014
+Equipment 30,897 26,993
+Furniture and fixtures 2,643 1,094
+Allowances for depreciation (34,405) (31,441)
+--------------------------
+20,177 17,720
+Goodwill, net of accumulated amortization of $4,217 in 2001 and $4,553 in
+2002 10,622 9,769
+Other assets 164 28
+--------------------------
+Total assets $ 68,061 $ 52,238
+==========================
+F-3
+Odetics, Inc.
+Consolidated Balance Sheets (continued)
+(In thousands, except share and per share amounts)
+March 31
+2001 2002
+------------------------
+Liabilities and stockholders' equity
+Current liabilities:
+Trade accounts payable $ 8,954 $ 6,611
+Accrued payroll and related 4,255 5,295
+Accrued expenses 2,352 1,373
+Contract reserve 2,290 600
+Billings in excess of costs and estimated earnings on uncompleted
+contracts 2,575 2,236
+Revolving line of credit 13,471 -
+Line of credit with related party - -
+Liabilities of discontinued operations 1,996 1,800
+Current portion of long-term debt 6,990 16,133
+------------------------
+Total current liabilities 42,883 34,048
+Revolving line of credit - 2,017
+Long-term debt, less current portion 4,800 25
+Minority interest - 10,893
+Commitments (Note 13)
+Stockholders' equity:
+Preferred stock:
+Authorized shares - 2,000,000
+Issued and outstanding - none - -
+Common stock, $.10 par value:
+Authorized shares - 50,000,000 of Class A and 2,600,000 of
+Class B
+Issued and outstanding shares - 9,468,620 of Class A and
+1,035,841 of Class B at March 31, 2001; 11,490,530 of Class
+A and 1,035,841 of Class B at March 31, 2002 1,050 1,252
+Paid-in capital 78,548 89,134
+Treasury stock, 93 and 93 shares in 2001 and 2002, respectively (1) (1)
+Notes receivable from employees (51) (51)
+Accumulated other comprehensive income (436) 241
+Accumulated deficit (58,732) (85,320)
+------------------------
+Total stockholders' equity 20,378 5,255
+------------------------
+Total liabilities and stockholders' equity $ 68,061 $ 52,238
+========================
+See accompanying notes.
+F-4
+Odetics, Inc.
+Consolidated Statements of Operations
+(In thousands, except per share information)
+Year ended March 31
+2000 2001 2002
+-------------------------------------------
+Net sales and contract revenues:
+Net sales $ 59,949 $ 56,119 $ 36,642
+Contract revenues 18,666 20,039 22,846
+-------------------------------------------
+78,615 76,158 59,488
+Costs and expenses:
+Cost of sales 49,147 44,869 22,245
+Cost of contract revenues 13,431 13,781 13,132
+Selling, general and administrative expenses 35,938 35,398 24,570
+Research and development expenses 12,978 13,753 8,115
+Special charge - 6,285 2,189
+-------------------------------------------
+114,494 114,086 70,251
+-------------------------------------------
+Loss from operations (32,879) (37,928) (10,763)
+Non-operating income (expense)
+Royalty income 38,437 17,825 -
+Other income (loss), net - 1,230 2,864
+Interest expense, net (2,048) (1,762) (4,190)
+-------------------------------------------
+Income (loss) before income tax 3,510 (20,635) (12,089)
+Income tax benefit - - 785
+-------------------------------------------
+Income (loss) from continuing operations before 3,510 (20,635) (11,304)
+minority interest
+Minority interest in earnings of subsidiary - - (1,910)
+-------------------------------------------
+Income (loss) from continuing operation 3,510 (20,635) (13,214)
+Loss from discontinued operations, including loss
+on disposal of $8,361 in 2002, net of taxes of $0 (5,789) (11,905) (12,924)
+Extraordinary loss from early extinguishment of
+debt, net of tax of $0 - - (450)
+-------------------------------------------
+Net loss $ (2,279) $ (32,540) $ (26,588)
+===========================================
+Basic earnings (loss) per share
+Continuing operations $ 0.39 $ (2.07) $ (1.17)
+Discontinued operations (0.64) (1.19) (1.15)
+Extraordinary items - - (0.04)
+-------------------------------------------
+Net loss $ (0.25) $ (3.26) $ (2.36)
+===========================================
+Diluted earnings (loss) per share
+Continuing operations $ 0.37 $ (2.07) $ (1.17)
+Discontinued operations (0.61) (1.19) (1.15)
+Extraordinary items - - (0.04)
+-------------------------------------------
+Net loss $ (0.24) $ (3.26) $ (2.36)
+===========================================
+Shares used in computing basic earnings
+(loss) per share 9,089 9,977 11,267
+===========================================
+Shares used in computing diluted earnings
+(loss) per share 9,444 9,977 11,267
+===========================================
+See accompanying notes.
+F-5
+Odetics, Inc.
+Consolidated Statements of Stockholders' Equity
+(In thousands)
+Common stock
+---------------------------------
+Shares outstanding
+---------------------- Notes Accumulative
+Class A Class B receivable other
+common common Paid-in Treasury from comprehensive
+stock stock Amount capital stock employees income
+------------------------------------------------------------------------------------
+Balance at March 31, 1999 7,941 1,060 $ 901 $ 59,579 $(240) $ (96) $ 92
+Issuances of common stock 234 - 22 1,621 218 - -
+Conversion of Class B common stock 8 (8) - - - - -
+Payments on notes receivable - - - - - 35 -
+Foreign currency
+translation adjustments - - - - - - 170
+Net loss - - - - - - -
+------------------------------------------------------------------------------------
+Balance at March 31, 2000 8,183 1,052 923 61,200 (22) (61) 262
+Issuances of common stock 1,270 - 127 17,348 21 - -
+Conversion of Class B common stock 16 (16) - - - - -
+Payments on notes receivable - - - - - 10 -
+Foreign currency translation
+adjustments - - - - - - (698)
+Net loss - - - - - - -
+------------------------------------------------------------------------------------
+Balance at March 31, 2001 9,469 1,036 1,050 78,548 (1) (51) (436)
+Issuances of Odetics common stock 2,022 - 202 3,716 - - -
+Issuance of Iteris common stock - - - 5,513 - - -
+Issuance of warrant - - - 1,357 - - -
+Foreign currency translation
+adjustments - - - - - - 677
+Net loss - - - - - - -
+------------------------------------------------------------------------------------
+Balance at March 31, 2002 11,491 1,036 $ 1,252 $ 89,134 $ (1) $ (51) $ 241
+====================================================================================
+Accumulated Comprehensive
+deficit Total income
+---------------------------------------
+Balance at March 31, 1999 $ (23,913) $ 36,323
+Issuances of common stock - 1,861
+Conversion of Class B common stock - -
+Payments on notes receivable - 35
+Foreign currency
+translation adjustments - 170 $ 170
+Net loss (2,279) (2,279) (2,279)
+---------------------------------------
+Balance at March 31, 2000 (26,192) 36,110 $ (2,109)
+==============
+Issuances of common stock - 17,496
+Conversion of Class B common stock - -
+Payments on notes receivable - 10
+Foreign currency translation
+adjustments - (698) $ (698)
+Net loss (32,540) (32,540) (32,540)
+---------------------------------------
+Balance at March 31, 2001 (58,732) 20,378 $ (33,238)
+==============
+Issuances of Odetics common stock - 3,918
+Issuance of Iteris common stock - 5,513
+Issuance of warrant - 1,357
+Foreign currency translation
+adjustments - 677 $ 677
+Net loss (26,588) (26,588) (26,588)
+---------------------------------------
+Balance at March 31, 2002 $ (85,320) $ 5,255 $ (25,911)
+=======================================
+See accompanying notes.
+F-6
+Odetics, Inc.
+Consolidated Statements of Cash Flows
+(In thousands)
+Year ended March 31
+2000 2001 2002
+-------------------------------------------
+Operating activities
+Net loss $ (2,279) $ (32,540) $ (26,588)
+Adjustments to reconcile net loss to net cash used in
+operating activities:
+Depreciation and amortization 7,185 4,967 3,776
+Amortization of warrants - - 1,230
+Write-off of discontinued subsidiary - - 8,361
+Minority interest in earnings of subsidiary - - 1,910
+Loss on sale of Iteris common stock - - 1,597
+Loss on disposal of assets - - 48
+Write-off of capitalized software - 4,014 -
+Gain on sale of product lines - (1,230) (3,385)
+Provision for losses on accounts receivable 745 78 102
+Changes in operating assets and liabilities (Note 15) 1,179 4,621 (5,284)
+-------------------------------------------
+Net cash provided by (used in) operating activities 6,830 (20,090) (18,233)
+Investing activities
+Purchases of property, plant and equipment, net (2,169) (2,502) (426)
+Repurchase of real estate option - (5,000) -
+Proceeds from sale of product lines - 1,877 9,884
+Proceeds from option to sell real estate 5,000 - -
+Software development costs (330) - -
+Purchase of net assets of acquired business (1,500) (42) (200)
+Other 213 (688) 677
+-------------------------------------------
+Net cash provided by (used in) investing activities 1,214 (6,355) 9,935
+Financing activities
+Proceeds from line of credit and long-term borrowings 23,966 26,644 28,720
+Principal payments on line of credit, long-term debt, and
+capital lease obligations (29,528) (19,857) (30,929)
+Proceeds from sale of Iteris common and preferred stock - - 8,697
+Proceeds from issuance of common stock 1,611 16,996 -
+-------------------------------------------
+Net cash provided by (used in) financing activities (3,951) 23,783 6,488
+-------------------------------------------
+Increase (decrease) in cash 4,093 (2,662) (1,810)
+Cash and cash equivalents at beginning of year 787 4,880 2,218
+-------------------------------------------
+Cash and cash equivalents at end of year $ 4,880 $ 2,218 $ 408
+===========================================
+See accompanying notes.
+F-7
+Odetics, Inc. and Subsidiary
+Notes to Consolidated Financial Statements
+March 31,2002
+1. Formation and Operations
+Odetics, Inc. (the Company) serves as a developer of technology oriented
+companies, each with its own marketplace, customers and products, including the
+Company's wholly-owned subsidiaries MAXxess Systems Inc., formerly known as Gyyr
+Incorporated (MAXxess), Broadcast, Inc. (Broadcast), Mariner Networks, Inc.
+(Mariner), Zyfer, Inc. (Zyfer), Odetics Europe Limited, Odetics GYYR Limited,
+Odetics Mariner Limited, Odetics Asia Pacific Pte. Ltd) and its majority-owned
+subsidiary, Iteris, Inc. (Iteris).
+During fiscal 2002 and 2001, the Company experienced operating losses of $10.8
+million and $37.9 million, respectively, and at March 31, 2002 has a working
+capital deficiency of $9.3 million. The Company financed its operations in
+fiscal 2001 and 2002 largely through cash received from the settlement of
+certain litigation with StorageTek (Note 16), debt and equity financings and
+through the sale of assets of certain of its subsidiaries.
+On May 28, 2002, the Company completed the sale and leaseback of its Anaheim,
+California facility for an aggregate sale price of $22.6 million. Under the
+terms of the sale and leaseback agreement, the Company will continue to lease
+one of the two buildings located on the property for an initial ten-year period
+at a rate of $152,150 per month and the other building for a period of 30 months
+at a rate of approximately $57,553 per month. Approximately $16.4 million of the
+proceeds from the sale was used to repay the outstanding indebtedness, and
+accrued interest under a promissory note that was secured by a first deed of
+trust on the Anaheim facility (Note 7). The balance of the proceeds is available
+for general working capital purposes. The gain on the sale of the facility of
+approximately $8.2 million will be deferred and amortized against rent expenses
+over the term of the leases.
+Notwithstanding the sale and leaseback transaction, the Company expects
+that its operations will continue to use net cash at least through the first
+half of fiscal 2003. The Company also expects to have an ongoing need to raise
+cash by securing additional debt or equity financing, or by divesting certain
+assets to fund its operations until they return to profitability and positive
+operating cash flow. However, the Company cannot be certain that it will be able
+to secure an additional debt or equity financing, or divest of certain assets on
+terms acceptable to us, or at all. The Company's future cash requirements will
+be highly dependent on its ability to control expenses as well as the successful
+execution of the revenue plans by each of its businesses. As a result, any
+projections of future cash requirements and cash flows are subject to
+substantial uncertainty.
+F-8
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+1. Formation and Operations (continued)
+These conditions, together with the Company's recurring operating losses, raise
+substantial doubt about the Company's ability to continue as a going concern.
+The accompanying consolidated financial statements do not include any
+adjustments to reflect the possible future effects on the recoverability and
+classification of assets or liabilities that may result from the outcome of this
+uncertainty.
+2. Summary of Significant Accounting Policies
+Principles of Consolidation
+The accompanying consolidated financial statements include the accounts of the
+Company and its subsidiaries. All significant intercompany accounts and
+transactions have been eliminated in consolidation.
+Use of Estimates
+The preparation of financial statements in conformity with generally accepted
+accounting principles requires management to make estimates and assumptions that
+affect the amounts reported in the financial statements and accompanying notes.
+Actual results could differ from those estimates. Significant estimates made in
+preparing the consolidated financial statements include the allowances for
+doubtful accounts and deferred tax assets, inventory reserves, certain accrued
+liabilities, costs to complete long-term contracts and estimates of future cash
+flows used to determine the recoverability of long lived assets.
+Revenue Recognition
+Product revenues and related cost of sales are recognized on the date of
+shipment or, if required, upon acceptance by the customer, provided that the
+Company believes collectibility of the net sales amount is probable.
+Accordingly, at the date revenue is recognized, the significant uncertainties
+concerning the sale have been resolved.
+Contract revenues is derived primarily from long-term contracts with
+governmental agencies. Contract revenue includes costs incurred plus a portion
+of estimated fees or profits determined on the percentage of completion method
+of accounting based on the relationship of costs incurred to total estimated
+costs. Any anticipated losses on contracts are charged to earnings when
+identified. Changes in job performance and estimated profitability, including
+those arising from contract penalty provisions and final contract settlements
+may result in revisions to cost and revenue and are recognized in the period in
+which the revisions are determined. Profit incentives are included in revenue
+when their realization is reasonably assured.
+F-9
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+2. Summary of Significant Accounting Policies (continued)
+Revenue Recognition (continued)
+Certain products sold by the Company include software which is integral to the
+functionality of the product. When such products do not require significant
+production, modification or customization of the software, revenue is recognized
+upon delivery, assuming the fee is fixed and collectibility is probable. If an
+arrangement requires significant production, modification or customization of
+the software, the arrangement is accounted for on the percentage of completion
+method of accounting as costs are incurred.
+Revenues from follow-on service and support, for which the Company charges
+separately, are recognized when earned. Revenues from computer software
+maintenance agreements are recognized ratably over the term of the agreements.
+When computer software maintenance is included in a software license agreement,
+an appropriate portion of the license fee is deferred and recognized over the
+maintenance period.
+Cash and Cash Equivalents
+Cash and cash equivalents consist of cash and short-term investments with
+maturities of less than ninety days.
+Concentration of Credit Risk
+The Company performs periodic credit evaluations of its customers' financial
+condition and generally does not require collateral. Credit losses have been
+within management's expectations and within amounts provided through the
+allowances for doubtful accounts. At March 31, 2001 and 2002, accounts
+receivable from governmental agencies and prime government contractors were
+approximately $3,719,000 and $4,774,000, respectively.
+Fair Values of Financial Instruments
+Fair values of cash and cash equivalents, and the current portion of long-term
+debt approximate the carrying value because of the short period of time to
+maturity. The fair value of long-term debt approximates carrying value because
+the related rates of interest approximate current market rates and has variable
+rates of interest.
+F-10
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+2. Summary of Accounting Policies (continued)
+Inventory Valuation
+Inventories are stated at the lower of cost or market. Cost is determined on the
+first-in, first-out method.
+Property, Plant and Equipment
+Property, plant and equipment are recorded at cost. Buildings are depreciated
+using the straight-line method over their estimated useful lives up to a period
+of forty years. Equipment, furniture and fixtures are depreciated principally by
+the declining balance method over their estimated useful lives ranging from four
+to eight years. Depreciation expense for the years ended March 31, 2000, 2001
+and 2002 was $3.7 million, $1.9 million and $2.3 million, respectively.
+Long-Lived Assets
+Long-lived assets and certain identifiable intangibles held and used by the
+Company are reviewed for impairment whenever events or changes in circumstances
+indicate that the carrying amount of an asset may not be recoverable. The
+Company believes no impairment of the carrying value of its long-lived assets,
+inclusive of goodwill, existed at March 31, 2002. The Company's analysis was
+based on an estimate of future undiscounted cash flows using forecasts contained
+in the Company strategic plan. It is at least reasonably possible that the
+Company's estimate of future undiscounted cash flows may change during fiscal
+2003. If the Company's estimate of future undiscounted cash flow should change
+or if the strategic plan is not achieved, future analyses may indicate
+insufficient future undiscounted cash flows to recover the carrying value of the
+Company's long-lived assets, in which case such assets would be written down to
+estimated fair value.
+Goodwill
+Goodwill, representing the excess of the purchase price over the fair value of
+the net assets of acquired entities, is being amortized using the straight-line
+method over an estimated useful lives of ten years.
+F-11
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+2. Summary of Accounting Policies (continued)
+Goodwill (continued)
+In 2001, the FASB issued Statements No. 141, Business Combinations (SFAS 141),
+and Statement No. 142, Goodwill and Other Intangible Assets (SFAS 142), which
+the Company adopted on April 1, 2002. Under the new rules, goodwill and
+intangible assets deemed to have indefinite lives will no longer be amortized,
+but, instead, will be subject to annual impairment tests. Other intangible
+assets will continue to be amortized over their useful lives. The Company will
+apply the new rules on accounting for goodwill and other intangible assets
+beginning in the first quarter of fiscal 2003. Pursuant to Statement 142, the
+Company is currently testing its goodwill for impairment and is unable at this
+time to estimate the amount of the impairment charge, if any, that may be
+required.
+On a pro forma basis, application of the non-amortization provision of SFAS 141
+would have resulted in a net loss in the years ended March 31, 2000, 2001 and
+2002 as follows:
+Year ended March 31
+(in thousands) 2000 2001 2002
+---------------------------------------
+Pro forma net loss $(592) $(30,616) $(25,072)
+Research and Development Expenditures
+Software development costs incurred subsequent to determination of technical
+feasibility are capitalized. Amortization of capitalized software costs is
+provided on a product-by-product basis at the greater of the amount computed
+using (a) the ratio of current gross revenues for the product to the total of
+current and anticipated future gross revenues or (b) the straight-line method
+over the remaining estimated economic life of the product. Amortization begins
+when product is available for general release to customers. Generally, an
+original estimated economic life of two to five years is assigned to capitalized
+software development costs.
+During fiscal 2000, 2001 and 2002, software development costs were amortized to
+cost of sales totaling $1,515,000, $940,000 and $237,000, respectively. During
+fiscal 2002, the Company discontinued certain product lines, resulting in the
+write-off of $1.9 million of previously capitalized software development costs.
+All other research and development expenditures are charged to expense in the
+period incurred.
+F-12
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+2. Summary of Accounting Policies (continued)
+Warranty
+The Company provides a warranty of one to two years on all products and records
+a related provision for estimated warranty costs at the date of the sale.
+Foreign Currency Translation
+The balance sheet accounts of the Company's foreign based subsidiaries are
+translated at the current year-end exchange rate and income statement items are
+translated at the average exchange rate for the year. Resulting translation
+adjustments are made directly to a separate component of stockholders' equity.
+Gains and losses resulting from transactions of the Company and its subsidiaries
+which are made in currencies different from their own are immaterial and are
+included in income as they occur.
+Comprehensive Income
+The only component of accumulated other comprehensive income is the cumulative
+foreign currency translation adjustment recorded in stockholders' equity.
+Income Taxes
+Deferred income tax assets and liabilities are computed for differences between
+financial statement and tax basis of assets and liabilities based on enacted tax
+laws and rates applicable to the period in which differences are expected to
+affect taxable income. Valuation allowances are established when necessary to
+reduce deferred tax assets to amounts which are more likely than not to be
+realized. The provision for income taxes is the taxes payable or refundable for
+the period plus or minus the change during the period in deferred income tax
+assets and liabilities.
+Earnings (Loss) Per Share
+Basic and diluted earnings (loss) per share is computed using the weighted
+average number of shares of common stock outstanding during the year and
+excludes the anti-dilutive effects of options.
+F-13
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+2. Summary of Accounting Policies (continued)
+Stock Compensation
+The Company has elected to follow Accounting Principles Board Opinion No. 25,
+Accounting for Stock Issued to Employees (APB 25) and related Interpretations in
+accounting for its employee stock options because the alternative fair value
+accounting provided for under Statement of Financial Accounting Standard No.
+123, Accounting for Stock-Based Compensation ("Statement 123"), requires use of
+option valuation models that were not developed for use in valuing employee
+stock options. Under APB 25, if the exercise price of the Company's employee
+stock options equals the market price of the underlying stock on the date of
+grant, no compensation expense is recognized.
+To calculate the pro forma information required by Statement 123, the Company
+uses the Black-Scholes option pricing model. The Black-Scholes model was
+developed for use in estimating the fair value of traded options which have no
+vesting restrictions and are fully transferable. In addition, option valuation
+models require the input of highly subjective assumptions including the expected
+stock price volatility. Because the Company's employee stock options have
+characteristics significantly different from those of traded options, and
+because changes in the subjective input assumptions can materially affect the
+fair value estimate, in management's option, the existing models do not
+necessarily provide a reliable single measure of the fair value of its employee
+stock options.
+In March 2000, the Financial Accounting Standards Board issued Interpretation
+No. 44, Accounting for Certain Transactions Involving Stock Compensation - an
+interpretation of APB Opinion No. 25 ("FIN 44"). FIN 44 clarifies the definition
+of employee for purposes of applying Accounting Practice Board Opinion No. 25,
+Accounting for Stock Issued to Employees, the criteria for determining whether a
+plan qualifies as a noncompensatory plan, the accounting consequence of various
+modifications to the terms of a previously fixed stock option or award, and the
+accounting for an exchange of stock compensation awards in a business
+combination. The adoption of FIN 44 did not have a material effect on the
+Company's financial position or results of operations.
+Advertising Expenses
+The Company expenses advertising costs as incurred. Advertising expense totaled
+$2,488,000, $3,491,000 and $1,264,000 in the years ended March 31, 2000, 2001
+and 2002, respectively.
+F-14
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+2. Summary of Accounting Policies (continued)
+Derivative Instruments and Hedging Activities
+In June 1998 Statement of Financial Accounting Standard No. 133, Accounting for
+Derivative Instruments and Hedging Activities ("Statement 133"), was issued,
+which establishes new standards for recording derivatives in financial
+statements. This statement requires recording all derivative instruments as
+assets or liabilities, measured at fair value. The Company adopted Statement
+133, as amended, on April 1, 2001. The adoption of Statement 133 did not have a
+significant impact on the consolidated results of operations, financial position
+or cash flows of the Company.
+Discontinued Operations
+In August of 2001, the Financial Accounting Standards Board (FASB) issued
+Statement of Financial Accounting Standards No. 144, Accounting for the
+Impairment or Disposal of Long-Lived Assets (SFAS 144). The Statement supersedes
+FASB Statement No. 121, Accounting for the Impairment of Long-Lived Assets and
+for Long-Lived Assets to be Disposed Of, however, it retains the fundamental
+provisions of that statement related to the recognition and measurement of the
+impairment of long-lived assets to be "held and used." SFAS 144 also supersedes
+the accounting and reporting provisions of Accounting Principles Board Opinion
+No. 30, Reporting the Results of Operation's - Reporting the Effects of Disposal
+of a Segment of a Business, and Extraordinary, Unusual and Infrequently
+Occurring Events and Transactions (APB 30), for the disposal of a segment of a
+business. Under SFAS 144, a component of a business that is held for sale is
+reported in discontinued operations if (i) the operations and cash flows will
+be, or have been, eliminated from the ongoing operations of the company and,
+(ii) the company will not have any significant continuing involvement in such
+operations. In the quarter ended September 30, 2001, the Company adopted the
+provisions of SFAS 144 effective April 1, 2001.
+In September of 2001, the Company's Board of Directors approved a plan to
+discontinue the operations of Mariner which was part of the Company's telecom
+products segment. The aggregate losses recognized to write down the assets of
+Mariner to their fair value less cost to sell were approximately $6.7 million.
+In addition, the Company accrued $1.7 million for severance and other direct
+costs to exit the operation.
+F-15
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+2. Summary of Accounting Policies (continued)
+Discontinued Operations (continued)
+The write-downs and costs are included in the loss from discontinued operations
+in the year ending March 31, 2002. Mariner's results of operations for all prior
+periods presented have been reclassified and presented as discontinued
+operations in the accompanying consolidated statement of operations. Interest
+expense was not allocated to discontinued operations because the discontinuance
+did not eliminate any of the Company's debt.
+The assets and liabilities of the discontinued operations consisted of the
+following:
+2001 2002
+-----------------------
+Accounts receivable, net $ 80 $ -
+Inventories 2,413 -
+Prepaid expenses and other assets 98 2
+Property, plant and equipment, net 958 203
+Capitalized software costs, net 2,090 -
+-----------------------
+Total assets of discontinued operations $ 5,639 $ 205
+=======================
+Accounts payable $ 1,690 $ 1,258
+Accrued expenses 306 542
+-----------------------
+Total liabilities of discontinued operations $ 1,996 $ 1,800
+=======================
+Reclassifications
+Certain amounts in the 2000 and 2001 consolidated financial statements have been
+reclassified to conform with the 2002 presentation.
+3. Acquisitions and Dispositions
+In October 1998, the Company, through Iteris, acquired Meyer, Mohaddes
+Associates, Inc., a provider of transportation, engineering and planning
+services (MMA). Pursuant to the terms of the merger agreement, the Company
+purchased all of the issued and outstanding shares of stock of MMA for $4.3
+million, by issuing 55,245 shares of the Company's Class A common stock valued
+at $250,000 and 810,153 shares of Iteris, Inc.'s common stock.
+F-16
+Odetics, Inc.
+Index to Consolidated Financial Statements
+3. Acquisitions and Dispositions (continued)
+The merger agreement provided for MMA shareholders to receive additional shares
+of the Company's Class A common stock with a then market value of $250,000 at
+each of April 16, 1999, October 16, 1999, April 16, 2000, October 16, 2000 and
+April 16, 2001 in the event the Company did not consummate an initial public
+offering of the common stock of Iteris, Inc. by each and any of those dates.
+Pursuant to this provision, Odetics issued an additional 219,706 shares of its
+Class A common stock to the MMA shareholders, which was recorded by the Company
+as additional goodwill. In addition, as a result of Iteris' failure to complete
+an initial public offering by October 2001, the MMA shareholder exercised their
+rights under the agreement and required Odetics to exchange 1,107,301 shares of
+Odetics' Class A common stock for 155,149 shares of Iteris common stock. This
+transaction resulted in additional goodwill of $2.5 million.
+During fiscal 2001, the Company sold certain assets of its solid state recording
+product line of its Zyfer subsidiary for cash proceeds of $1.9 million. In
+connection with these sales the Company recorded gains aggregating $1.2 million.
+In April 2001, the Company sold its Vortex Dome and Quarterback Controller
+product lines for approximately $1.1 million in net cash proceeds. In connection
+with this transaction, the Company realized a gain of $0.1 million.
+In September 2001, the Company sold substantially all of the assets of its Gyyr
+CCTV Products divisions for $8.8 million in cash, plus the assumption of $1.0
+million in debt. In connection with this transaction, the Company wrote-off
+goodwill with a net book value of $2.3 million and, net of this write-off,
+realized a gain of $4.3 million.
+F-17
+Odetics, Inc.
+Index to Consolidated Financial Statements
+4. Special Charge
+During fiscal 2001 and 2002, the Company approved a number of actions to reduce
+operating expenses and improve profitability and cash flows. These actions
+included a reduction in workforce of 222 and 130 employees in 2001 and 2002,
+respectively, and the discontinuance of certain product lines. As a result of
+these actions the company recorded the following as special charge (in
+thousands):
+Severance Write-off of Write-off Write-off
+and related capitalized of of deferred
+costs software goodwill costs Total
+-------------------------------------------------------------------
+Special provision $ 1,305 $ 3,452 $ 562 $ 966 $ 6,285
+Cash expenditures
+Non-cash activities (1,305) (3,452) (562) (966) (6,285)
+-------------------------------------------------------------------
+Balance at March 31, 2001 - - - - -
+Special provision 2,189 - - - 2,189
+Cash expenditures (858) - - - (858)
+-------------------------------------------------------------------
+Balance at March 31, 2002 $ 1,331 $ - $ - $ - $ 1,331
+===================================================================
+In addition during fiscal 2001, the Company reserved or wrote-off inventory in
+the amount of $3.1 million, primarily related to discontinued products in its
+Broadcast and Gyyr subsidiaries. The charge is included in cost of sales in the
+accompanying consolidated statement of operations.
+5. Real Estate Option
+In July 1999, the Company sold an option to an investment company controlled by
+certain officers and shareholders of the Company, for an aggregate purchase
+price of $5.0 million to purchase certain real property of Odetics. In August
+2000 the Company repurchased the option for $5.6 million which represented the
+original purchase price plus accrued interest.
+F-18
+Odetics, Inc.
+Index to Consolidated Financial Statements
+6. Costs and Estimated Earnings on Uncompleted Contracts
+Costs incurred, estimated earnings and billings on uncompleted long-term
+contracts are as follows:
+March 31
+2001 2002
+------------------------------------
+(In thousands)
+Costs incurred on uncompleted contracts $ 14,054 $ 17,998
+Estimated earnings 1,054 1,355
+------------------------------------
+15,108 19,353
+Less billings to date 14,387 18,024
+------------------------------------
+$ 721 $ 1,329
+====================================
+Included in accompanying balance sheets:
+Costs and estimated earnings in excess of billings on
+uncompleted contracts $ 3,296 $ 3,565
+Billings in excess of costs and estimated earnings on
+uncompleted contracts 2,575 2,236
+------------------------------------
+$ 721 $ 1,329
+====================================
+Costs and estimated earnings in excess of billings at March 31, 2001 and 2002
+include $232,575 and $136,114 respectively, that were not billable as certain
+milestone objectives specified in the contracts had not been attained.
+Substantially all costs and estimated earnings in excess of billings at March
+31, 2002 are expected to be billed and collected during the year ending March
+31, 2003.
+7. Revolving Lines of Credit and Long-Term Debt
+In February 2002, the Company entered into a $1.25 million line of credit with a
+partnership controlled by the Company's Chairman of the Board. The line of
+credit is collateralized by substantially all of the Company's assets other than
+real property. Borrowings on the line of credit bear interest at the prime rate
+plus 4% (8.75% at March 31, 2002) and matures in July 2003.
+F-19
+Odetics, Inc
+Notes to Consolidated Financial Statements
+7. Revolving Lines of Credit and Long-Term Debt (continued)
+In August 2001, the Company through Iteris, entered into a loan and security
+agreement with a maximum available credit line of $5 million. At March 31, 2002,
+$767,000 was outstanding under this line of credit and amounts available for
+future borrowing totalled $3,309,000. Under the terms of the agreement, the
+Company may borrow against its eligible accounts receivable and the value of its
+eligible inventory, as defined. Interest on borrowed amounts is payable monthly
+at the prime rate plus 2% (6.75% at March 31, 2002). Additionally, Iteris is
+obligated to pay an unused line fee of 0.5% per annum applied to the amount by
+which the maximum credit amount exceeds the average daily principal balance
+during the preceding month, and a monthly collateral management fee of $2,000.
+The agreement is secured by substantially all of Iteris' assets and expires in
+August 2004. Either party can terminate the agreement with thirty days written
+notice. Should Iteris elect to terminate the agreement, a one-time termination
+fee of 3%, 2% and 1% of the maximum credit limit would apply in years 1 through
+3, respectively.
+In January 2000, the Company through Iteris, entered into a joint venture
+agreement, pursuant to which Iteris obtained a Subordinated Convertible
+Promissory Note in the amount of $3.75 million. In July 2001, the note holder
+converted the note and related accrued interest into common and preferred stock
+of Iteris (Note 11).
+In May 2001, the Company entered into a $16 million promissory note secured by a
+first trust deed on its principle facilities in Anaheim, California which bore
+interest at 10% per annum. The promissory note was paid in full at its scheduled
+maturity date in May 2002 (Note 1). In connection with the note the Company
+issued warrants to the lender to purchase 426,667 shares of Class A common stock
+at an exercise price of $4.00 per share. The Company repriced the warrants to
+$3.00 per share, in connection with a forbearance agreement negotiated in
+November of 2001. The issuance of the warrant represented a discount on the note
+totaling $1,357,000, which is being amortized over the life of the note. At
+March 31, 2002, $244,000 of the discount had not been amortized and is reflected
+as a reduction of the outstanding note balance.
+Approximately $6.0 million of the proceeds of the promissory note was used to
+retire the pre-existing note payable on the Anaheim facility, which included a
+prepayment penalty of $450,000. This prepayment penalty is reflected as an
+extraordinary item in the accompanying consolidated statement of operations.
+F-20
+Odetics, Inc
+Notes to Consolidated Financial Statements
+7. Revolving Lines of Credit and Long-Term Debt (continued)
+Long-term debt consisted of the following:
+March 31
+2001 2002
+-------------------------
+(In thousands)
+Note payable, net of discount of $244,000 at March 31, 2002, paid
+in May 2002 $ - $ 15,756
+Note payable, paid in May 2001 5,874 -
+Note payable, converted to common and preferred stock of Iteris in
+July 2001 3,750 -
+Note payable, assumed in September 2001 by the purchaser of the Gyyr
+CCTV Products division (Note 3) 1,000 -
+Notes payable, accruing interest at 7.55% to 17.08%,
+collateralized by equipment, payable in monthly installments
+through 2003 1,166 402
+-------------------------
+11,790 16,158
+Less current portion 6,990 16,133
+-------------------------
+$ 4,800 $ 25
+=========================
+The annual maturities of long-term debt at March 31, 2002 are as follows:
+(In thousands)
+2003 $ 16,133
+2004 25
+--------------
+$ 16,158
+==============
+F-21
+Odetics, Inc
+Notes to Consolidated Financial Statements
+8. Income Taxes
+During fiscal 2002, the Company recognized an income tax benefit of
+$785,000 related to the recovery of net operating loss carrybacks made available
+under the Job Creation and Workers Association Act of 2002.
+The reconciliation of the income tax benefit from continuing operations to
+taxes computed at U.S. federal statutory rates is as follows:
+Year ended March 31
+2000 2001 2002
+------------------------------------------------------
+(In thousands)
+Income tax expense (benefit) at statutory
+rates $ 1,193 $ (7,015) $ (4,111)
+Recognition of net operating losses - - (785)
+Increase (decrease) of valuation allowance
+associated with federal deferred tax assets (2,741) 4,304 2,169
+Foreign losses recorded without benefit 1,258 2,255 1,489
+Nondeductible goodwill amortization 191 153 176
+Other 99 303 277
+------------------------------------------------------
+$ - $ - $ (785)
+======================================================
+United States and foreign loss from continuing operations before income taxes
+are as follows:
+Year ended March 31
+2000 2001 2002
+------------------------------------------------------
+(In thousands)
+Pretax income (loss):
+Domestic $ 4,488 $ (16,110) $ (7,709)
+Foreign (978) (4,525) (4,380)
+------------------------------------------------------
+$ 3,510 $ (20,635) $ (12,089)
+======================================================
+F-22
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+8. Income Taxes (continued)
+The components of deferred tax assets and liabilities are as follows:
+2001 2002
+----------------------
+(In thousands)
+Deferred tax assets:
+Inventory reserves $ 738 $ 716
+Deferred compensation and other payroll accruals 1,074 1,192
+Net operating loss carryforward 14,578 21,269
+Credit carryforwards 2,051 1,503
+Bad debt reserve and other reserves 1,300 357
+Other, net 281 402
+---------------------
+Total deferred tax assets 20,022 25,439
+Valuation allowance for deferred tax assets (17,378) (23,557)
+---------------------
+Net deferred tax assets 2,644 1,882
+---------------------
+Deferred tax liabilities:
+Tax over book depreciation 1,990 1,416
+Capitalized interest and taxes 434 420
+Cash to accrual adjustment 174 -
+Other, net 46 46
+---------------------
+Total deferred tax liabilities 2,644 1,882
+---------------------
+Net deferred taxes $ - $ -
+=====================
+At March 31, 2002, for federal income tax purposes, the Company had
+approximately $1,430,000 in general business credit carryforwards, which expire
+at various dates beginning in 2003. The Company also has $49,746,000 of net
+operating loss carryforwards for federal income tax purposes that begin to
+expire in 2019. For financial reporting purposes, a valuation allowance has been
+recorded to offset the deferred tax asset related to these credits and net
+operating losses. Any future benefits recognized from the reduction of the
+valuation allowance related to these carryforwards will result in a reduction of
+income tax expense.
+In December 2001, the Company's ownership interest in Iteris fell below the
+threshold required for the Company to file a consolidated tax return. As a
+result, Iteris will no longer be included in the Odetics consolidated group for
+income tax purposes, and instead will be required to file a separate tax return.
+At March 31, 2002, for federal income tax purposes, Iteris had approximately
+$3,200,000 of net operating loss carryforwards that begin to expire in 2021.
+F-23
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+8. Income Taxes (continued)
+Because of the "change of ownership" provision of the Tax Reform Act of 1986,
+utilization of the Company's net operating loss carryforwards may be subject to
+an annual limitation against taxable income in future periods. As a result of
+the annual limitation, a portion of these carryforwards may expire before
+ultimately becoming available to reduce future income tax liabilities.
+9. Associate Incentive Programs
+Under the terms of a Profit Sharing Plan, the Company contributes to a trust
+fund such amounts as are determined annually by the Board of Directors. No
+contributions were made in 2000, 2001 or 2002.
+In May 1990, the Company adopted a 401(k) Plan as an amendment and replacement
+of the former Associate Stock Purchase Plan that was an additional feature of
+the Profit Sharing Plan. Under the 401(k) Plan, eligible associates voluntarily
+contribute to the plan up to 15% of their salary through payroll deductions. The
+Company matches 50% of contributions up to a stated limit. Under the provisions
+of the 401(k) Plan, associates have four investment choices, one of which is the
+purchase of Odetics, Class A common stock at market price. Company matching
+contributions were approximately $746,000, $812,000 and $722,000 in 2000, 2001
+and 2002, respectively.
+F-24
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+9. Associate Incentive Programs (continued)
+Effective April 1, 1987, the Company established a noncontributory Associate
+Stock Ownership Plan (ASOP) for all associates with more than six months of
+eligible service. The ASOP provides that Company contributions, which are
+determined annually by the Board of Directors, may be in the form of cash or
+shares of Company stock. The Company contributions to the ASOP were
+approximately $69,000, $17,000 and $0 in 2000, 2001 and 2002, respectively.
+Shares distributed through the ASOP Plan were included in total outstanding
+shares used in the earnings per share calculation.
+10. Deferred Compensation Plans
+During 1986, the Company adopted an Executive Deferral Plan under which certain
+executives may defer a portion of their annual compensation. All deferred
+amounts earn interest, generally with no guaranteed rate of return. Compensation
+charged to operations and deferred under the plan totaled $110,000, $128,000 and
+$66,000 for 2000, 2001 and 2002, respectively.
+11. Iteris Preferred and Common Stock
+In July 2001, Iteris issued 1,781,268 shares of its Series A Preferred Stock
+(Iteris Preferred Stock) to an institutional investor in exchange for $5.0
+million in cash. In addition, Iteris issued 1,343,645 shares of its Series A
+Preferred Stock and 547,893 shares of its common stock in exchange for $500,000
+in cash and the retirement of its $3.75 million Subordinated Convertible
+Promissory Note plus related accrued interest of $0.4 million.
+Shares of Iteris Preferred Stock are convertable into shares of Iteris common
+stock at the conversion rate in effect at the time, as defined. Each share of
+Iteris Preferred Stock will automatically convert into shares of Iteris common
+stock immediately upon the closing of a firmly underwritten public offering
+pursuant to an effective registration statement under the Securities Act of 1933
+with aggregate gross proceeds to the Company of not less than $30 million and
+price per share of not less than two times the original Series A Preferred Stock
+issue price of $2.80 per share.
+F-25
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+11. Iteris Preferred and Common Stock (continued)
+In the event that the Company fails to consummate an initial public offering of
+Iteris common stock or complete a sale of Iteris to a third party with aggregate
+proceeds of $25 million by January 1, 2004 and/or the holders of Series A
+Preferred Stock elect not to exercise their rights to convert into Common Stock,
+the Company will be obligated to redeem the Series A shares at a sum equal to
+two times the original Series A Preferred Stock issue price.
+At March 31, 2002, the liquidation preference on Iteris Preferred Stock totals
+$17.5 million. The difference between the initial issue price, net of related
+issuance costs, and the liquidation preference is being amortized over the
+redemption period and is reflected in minority interest in earnings of
+subsidiary in the accompanying consolidated statement of operations.
+In August and December 2001, Odetics sold 1,539,241 shares of Iteris common
+stock that it held at an aggregate purchase price of $3.8 million to a group of
+investors, which included certain members of management of Odetics and Iteris.
+In connection with this transaction, Odetics realized a loss of $1.6 million
+which is reflected in other income (loss) in the accompanying consolidated
+statement of operations. At March 31, 2001, Odetics owned 78.2% of the
+outstanding common stock of Iteris.
+12. Stock Option Plans
+The Company has adopted an Associate Stock Option Plan which provides that
+options for shares of the Company's unissued Class A common stock may be granted
+to directors and associates of the Company. Options granted enable the option
+holder to purchase one share of Class A common stock at prices which are equal
+to or greater than the fair market value of the shares at the date of grant.
+Options expire ten years after date of grant or 90 days after termination of
+employment and vest ratably at 33% on each of the first three anniversaries of
+the grant date.
+F-26
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+12. Stock Option Plans (continued)
+A summary of all Company stock option activity is as follows:
+Year ended March 31
+2000 2001 2002
+---------------------------------------------------------------------
+Weighted Weighted Weighted
+Average Average Average
+Exercise Exercise Exercise
+Options Price Options Price Options Price
+---------------------------------------------------------------------
+(In thousands, except per share data)
+Options outstanding at
+beginning of year 628 $ 5.27 801 $ 7.68 804 $8.44
+Granted 358 10.36 120 13.47 30 2.28
+Exercised (152) 4.65 (24) 7.95 - -
+Canceled (33) 4.65 (93) 8.21 (505) 8.06
+--------- --------- ---------
+Options outstanding at end of
+year 801 $ 7.68 804 $ 8.44 329 $8.37
+=====================================================================
+Exercisable at end of year 219 531 237
+=====================================================================
+Available for grant at end of
+year 114 487 1,322
+========= ========= =========
+Weighted average fair value of
+options granted $ 5.25 $ 7.03 $1.20
+========== ========== ==========
+The exercise price for options outstanding as of March 31, 2002, ranged from
+$2.28 to $15.625. The weighted-average remaining contractual life of those
+options is 8.3 years.
+F-27
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+12. Stock Option Plans (continued)
+Pro Forma Disclosures of the Effect of Stock-Based Compensation Plans
+In calculating pro forma information regarding net income and earning per share,
+as required by Statement No. 123, the fair value was estimated at the date of
+grant using a Black-Scholes option pricing model with the following assumption:
+Years ended March 31
+2000 2001 2002
+-------------------------------
+Dividend rate 0.0 0.0 0.0
+Expected life - years 7.0 7.0 7.0
+Risk-free interest rate 6.0 6.0 4.5
+Volatility of common stock 0.4 0.4 0.4
+For purposes of pro forma disclosures, the estimated fair value of the options
+is amortized to expense over the options' vesting period. The Company's pro
+forma information for the year ended March 31, 2000, 2001 and 2002 follows (in
+thousands, except per share data):
+2000 2001 2002
+-----------------------------------
+Pro forma:
+Net loss $ (2,969) $ (33,512) $ (26,789)
+Basic and diluted loss per share $ (0.33) $ (3.36) $ (2.38)
+Iteris, Inc.'s Stock Options
+In September 1997, Iteris granted options to purchase up to 899,960 shares of
+its common stock to certain members of its senior management at an exercise
+price of $1.07 per share. As of March 31, 2002, options to purchase 759,345
+shares of common stock were outstanding.
+Subsequently, Iteris' Board of Directors adopted and approved the 1998 Stock
+Incentive Plan (the Plan), as amended in February 2000, authorized 3,000,000
+shares of Iteris' common stock for issuance under the Plan. Options to purchase
+2,228,492 shares of common stock, at exercise prices ranging from $1.60 to $9.07
+per share, were outstanding at March 31, 2002. Under the Plan, options expire
+ten years after date of grant or 90 days after termination of employment. The
+options granted vested ratably at 25% on each of the first four anniversaries of
+the grant date.
+F-28
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+12. Stock Option Plans (continued)
+Zyfer, Inc.'s Stock Option Plans
+In April 2000, Zyfer's Board of Directors adopted a Special Executive Stock
+Option Plan which provides for the granting of stock options for shares of
+Zyfer's unissued common stock to certain officers, key employees, non-employee
+members of the Board of Directors, consultants and independent contractors. A
+total of 1,176,500 shares of Zyfer's common stock are reserved for issuance
+under this plan.
+In April 2000, Zyfer's Board of Directors also adopted the 1999 Employee Stock
+Option Plan which provides options for shares of Zyfer's common stock to
+associates, non-employee members of the Board of Directors of Zyfer, Odetics or
+other Odetics subsidiaries and independent consultants. A total of 588,500
+shares of Zyfer's common stock are reserved for issuance under this plan.
+Options expire ten years after the date of grant or 90 days after termination of
+employment and vest upon the optionee's completion of five years of service
+measured from the vesting commencement date as specified on the stock option
+agreements. The vesting of these options will accelerate upon initial public
+offering of Zyfer's common stock. Options to purchase 1,266,500 shares of
+Zyfer's common stock under these plans were outstanding at March 31, 2002.
+13. Commitments
+The Company has lease commitments for facilities in various locations throughout
+the United States. The annual commitment under these noncancelable operating
+leases at March 31, 2002 is as follows:
+Fiscal Year (in thousands)
+-----------
+2003 $ 327
+2004 162
+2005 56
+--------------------
+$ 545
+====================
+Rent expense under operating leases totaled $973,000, $1,040,000 and $1,139,000,
+respectively for the years ended March 31, 2000, 2001 and 2002.
+F-29
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+13. Commitments (continued)
+Common stock reserved for future issuance at March 31, 2002:
+Issuable under stock options plans 1,651,000
+Issuable upon the exercise of warrants 426,667
+14. Business Segment and Geographic Information
+The Company operates in three reportable segments: intelligent transportation
+systems, video products which includes products for the television broadcast and
+video security markets, and telecommunications. The accounting policies of the
+reportable segments are the same as those described in the summary of
+significant accounting policies except that certain expenses, such as interest,
+amortization of certain intangibles and certain corporate expenses are not
+allocated to the segments. In addition, certain assets including cash and cash
+equivalents, deferred taxes and certain long-lived and intangible assets are not
+allocated to the segments. Intersegment sales are recorded at the selling
+segment's cost plus profit.
+The reportable segments are each managed separately because they manufacture and
+distribute distinct products or provide services with different processes.
+Selected financial information for the Company's reportable segments as of and
+for the years ended March 31, 2000, 2001 and 2002 follows:
+Intelligence
+(In thousands) Transportation Video Products Telecom Product Total
+--------------------------------------------------------------------------------------------------------------
+Year ended March 31, 2000
+Revenue from external customers $ 23,411 $ 38,958 $ 7,572 $ 69,941
+Intersegment revenues - 6,001 84 6,085
+Depreciation and amortization 1,962 2,637 732 5,331
+Segment income (loss) (4,407) (16,350) (2,035) (22,792)
+Segment assets 19,240 38,831 5,473 63,544
+Expenditure for long-lived assets 470 760 308 1,538
+F-30
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+14. Business Segment and Geographic Information (continued)
+Intelligence Video Telecom
+(In thousands) Transportation Products Product Total
+------------------------------------------------------------------------------------------------------------
+Year ended March 31, 2001
+Revenue from external customers $ 28,057 $ 39,726 $ 6,972 $ 74,755
+Intersegment revenues - 1,183 57 1,240
+Depreciation and amortization 1,502 1,849 183 3,534
+Segment income (loss) (3,942) (15,767) (2,137) (21,846)
+Segment assets 18,709 22,706 6,326 47,741
+Expenditure for long-lived assets, net 1,392 631 206 2,150
+Year ended March 31, 2002
+Revenue from external customers $ 37,308 $ 16,715 $ 5,465 $ 59,488
+Intersegment revenues - - - -
+Depreciation and amortization 1,759 547 313 2,619
+Segment income (loss) 2,979 (3,306) (3,787) (4,114)
+Segment assets 25,736 5,805 5,016 36,557
+Expenditure for long-lived assets, net 272 22 63 357
+F-31
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+14. Business Segment and Geographic Information (continued)
+The following reconciles segment income to consolidated income before income
+taxes and segment assets and deprecation and amortization to consolidated assets
+and consolidated depreciation and amortization:
+(In thousands) 2000 2001 2002
+-----------------------------------------------------------------------------------------------------------
+Revenue
+Total revenues for reportable segments $ 76,026 $ 75,995 $ 59,488
+Non reportable segment revenues 8,674 1,403 -
+Elimination of Intersegment sales (6,085) (1,240) -
+-------------------------------------------
+Total consolidated revenues $ 78,615 $ 76,158 $ 59,488
+===========================================
+Segment Income (Loss)
+Total income (loss) for reportable segments $ (22,792) $ (21,846) $ (4,114)
+Other income (loss) (3,618) (2,893) 2,726
+Unallocated amounts:
+Corporate and other expenses (6,469) (5,674) (4,322)
+Royalty income 38,437 17,825 -
+Special charge - (6,285) (2,189)
+Interest expense (2,048) (1,762) (4,190)
+-------------------------------------------
+Income (Loss) from continuing operations before
+income taxes $ 3,510 $ (20,635) $ (12,089)
+===========================================
+Assets
+Total assets for reportable segments $ 63,544 $ 47,741 $ 36,557
+Assets held at Corporate 18,306 20,320 15,681
+-------------------------------------------
+Total assets $ 81,850 $ 68,061 $ 52,238
+===========================================
+Depreciation and Amortization
+Depreciation and amortization for reportable segments $ 5,331 $ 3,534 $ 2,619
+Other 1,854 1,433 1,157
+-------------------------------------------
+Total depreciation and amortization $ 7,185 $ 4,967 $ 3,776
+===========================================
+F-32
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+14. Business Segment and Geographic Information (continued)
+Selected financial information for the Company's operations by geographic
+segment is as follows:
+(In thousands) 2000 2001 2002
+-----------------------------------------------------------------------------------------------------------
+Geographic Area Revenue
+United States $ 63,193 $ 60,595 $ 53,461
+Europe 8,509 7,340 3,466
+Asia Pacific Rim 2,821 2,703 1,762
+Other 4,092 5,520 799
+-----------------------------------------
+Total net revenue $ 78,615 $ 76,158 $ 59,488
+=========================================
+Geographic Area Long-Lived Assets
+United States $ 35,897 $ 30,526 $ 27,496
+Europe 1,101 414 -
+Asia Pacific Rim 15 23 21
+-----------------------------------------
+Total long-lived assets $ 37,013 $ 30,963 $ 27,517
+=========================================
+15. Supplemental Cash Flow Information
+Year ended March 31
+2000 2001 2002
+------------------------------------------
+(In thousands)
+Net cash used in changes in operating assets and
+liabilities, net of acquisitions:
+(Increase) decrease in accounts receivable $ 4,568 $ (882) $ 3,897
+(Increase) decrease in net costs and estimated
+earnings in excess of billings (833) 1,259 (608)
+(Increase) decrease in inventories (2,227) 4,499 (1,542)
+Increase in prepaids and other assets 428 861 (735)
+Increase (decrease) in accounts payable and accrued
+expenses (757) (1,116) (3,170)
+Change in net operating assets of discontinued
+operations - - (3,126)
+------------------------------------------
+Net cash used in changes in operating assets and
+liabilities $ 1,179 $ 4,621 $ (5,284)
+==========================================
+Cash paid (received) during the year:
+Interest $ 1,995 $ 1,768 $ 2,514
+Income taxes paid (refunded) (1,144) 86 -
+Noncash transactions during the year:
+Exchange of note payable and accrued interest for
+Iteris stock $ - $ - $ 4,203
+Acquisition of business for note payable 2,000 -
+Stock issuance to former MMA shareholders 251 500 2,737
+Contribution of common stock to 401(k) Plan - - 791
+Issuance of common stock in settlement of accounts
+payable - - 390
+F-33
+Odetics, Inc.
+Notes to Consolidated Financial Statements
+16. Legal Proceedings
+On October 11, 1999, the Company settled a patent infringement case it had
+brought against Storage Technology Corporation (StorageTek). Through an
+agreement, StorageTek agreed to pay the Company a license fee totaling $100.0
+million for use of the Company's United States Patent No. 4,779,151. Under the
+agreement, the license fee was payable in three installments: $80.0 million upon
+signing of the agreement, and two annual installments of $10.0 million payable
+in each of October 2000 and 2001. In connection with the initial payment, the
+Company received $38.4 million, net of legal fees and other direct expenses,
+which is reflected in the accompanying consolidated statement of operations as
+royalty income.
+On June 12, 2000, the Company and StorageTek amended the agreement, whereby
+StorageTek agreed to pay a final discounted payment of $17.8 million immediately
+in full settlement of the $20.0 million otherwise due to complete the
+settlement, which is reflected in the accompanying consolidated financial
+statements as royalty income.
+17. Supplementary Quarterly Consolidated Financial Data (Unaudited)
+All quarters presented in the following schedule have been restated for the
+discontinuance of Mariner in September 2001.
+Income
+Income per Share
+(Loss) from Net from
+Net Gross Continuing Income Continuing
+Sales Profit Operations (Loss) Operations
+-----------------------------------------------------
+June 30, 2000(1) 19,317 4,550 9,169 7,430 .95
+September 30, 2000 18,844 4,605 (9,358) (12,266) (.97)
+December 31, 2000(2) 18,533 1,976 (16,748) (19,951) (1.60)
+March 31, 2001 19,464 6,377 (3,698) (7,753) (.35)
+June 30, 2001 16,384 5,387 (4,355) (7,775) (.41)
+September 30, 2001(3) 15,977 6,149 (4,291) (15,164) (.41)
+December 31, 2001 13,618 5,753 (2,332) (2,332) (.20)
+March 31, 2002 13,509 6,822 (2,236) (1,317) (.18)
+(1) On June 12, 2000 the Company amended the settlement of a patent
+infringement case whereby the Company accepted a final discounted payment of
+$17.8 million to complete the settlement. The settlement is reflected in
+the operating results for the quarter ended June 30, 2000.
+(2) During the quarter ended December 31, 2000, the Company effected a
+restructuring that included a reduction of approximately 25% of its total
+workforce and discontinuation of certain product lines. As a result of
+these actions, the Company incurred charges in the amount of $9.4 million,
+which is reflected in the operating results for the quarter ended December
+31, 2000.
+(3) During the quarter ended September 30, 2001, the Company discontinued the
+operations of its Mariner subsidiary and restructured its European
+operations. In connection with these actions the Company recorded severance
+and other reserves and wrote down assets totaling $9.9 million.
+F-34
+Schedule II
+Odetics, Inc.
+Valuation and Qualifying Accounts
+Balance at Charged to Balance at
+Beginning of Costs and Charged to Deductions End of
+Description Period Expenses Accounts Describe Period
+----------------------------------------------- -------------- ------------ ------------ ------------- -----------
+Year ended March 31, 2000
+Deducted from asset accounts:
+Allowance for doubtful accounts ........... $ 839,000 $1,293,000 $ (64,000) $ -- $2,068,000
+Reserve for inventory obsolescence ...... 3,171,000 1,438,000 (1,123,000) -- 3,486,000
+Year ended March 31, 2001
+Deducted from asset accounts:
+Allowance for doubtful accounts ........... $2,068,000 $ 78,000 $ (502,000) $ -- $1,644,000
+Reserve for inventory obsolescence ...... 3,486,000 4,925,000 (4,443,000) -- 3,968,000
+Year ended March 31, 2002
+Deducted from asset accounts:
+Allowance for doubtful accounts ........... $1,644,000 $ 102,000 $(1,365,000) $ -- $ 381,000
+Reserve for inventory obsolescence ...... 3,968,000 363,000 (2,264,000) -- 2,067,000
\ No newline at end of file
diff --git a/raw/filings/0000350868/2001/0001017062-02-001321/filing_metadata.csv b/raw/filings/0000350868/2001/0001017062-02-001321/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..f753288757428cbbb3ceab386d62879bafaf8fcc
--- /dev/null
+++ b/raw/filings/0000350868/2001/0001017062-02-001321/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000350868,ITI,"ITERIS, INC.",10-K,2002-07-01,2002-03-31,2002-07-01T21:19:28.000Z,0001017062-02-001321,d10k.txt,"ODETICS, INC. FORM 10-K",242610,0,0,https://www.sec.gov/Archives/edgar/data/350868/000101706202001321/d10k.txt,https://www.sec.gov/Archives/edgar/data/350868/000101706202001321/,2001,2001,1
diff --git a/raw/filings/0000350868/2001/0001017062-02-001321/item1.txt b/raw/filings/0000350868/2001/0001017062-02-001321/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..88f8dc7fc2208453bb7ca6b0b9b4be3f5d00e5d4
--- /dev/null
+++ b/raw/filings/0000350868/2001/0001017062-02-001321/item1.txt
@@ -0,0 +1,854 @@
+ITEM 1. BUSINESS
+General
+Odetics, Inc. provides products, systems, and services that control and
+manage the use of public roadways, secure access to public and private
+facilities, and secure the delivery of digital communications. Our company was
+founded in 1969 to supply digital recorders for use in the United States space
+program. We pioneered new designs and standards for digital magnetic tape
+recorders offering high reliability and enhanced performance in the adverse
+environment attendant to space flight. In the 1970s, we broadened our
+information automation product line to include time-lapse videocassette
+recorders for commercial security and surveillance applications, and entered the
+business of manufacturing telecom network synchronization products. Through our
+Gyyr Incorporated subsidiary, we became a leading supplier of time-lapse
+videotape cassette recorders, and we pioneered new products incorporating
+digital video technologies and related CCTV products used in security and
+surveillance systems. In April 2001, we sold Gyyr's Vortex Dome and Quarterback
+Controller product lines. Then in September 2001, we sold the assets of our CCTV
+product line, and changed the name of our Gyyr subsidiary to MAXxess Systems
+Inc. to continue to pursue the security market with electronic access control
+products and systems.
+Beginning in the late 1970s, we developed and manufactured telecom
+synchronization products in our Communications division. We incorporated our
+Communications division in fiscal 1999 as our wholly-owned subsidiary, Zyfer,
+Inc., as part of our business expansion to develop products focused on the
+security aspects of data traffic over ground and satellite links, and network
+communications.
+Leveraging our expertise in video image processing, we entered into the
+intelligent transportation system ("ITS") business with the introduction of a
+video-based vehicle detection system in 1993. In June 1997, we acquired certain
+assets comprising the Transportation Systems business from Rockwell
+International, creating our ITS division, which expanded our offerings to
+include advanced traffic management systems and advanced traveler information
+systems. We incorporated our ITS division in 1998 as Odetics ITS, Inc. In
+October 1998, we broadened our systems offerings by acquiring Meyer, Mohaddes
+Associates, Inc. In January 2000, we reincorporated Odetics ITS in Delaware and
+changed its name to Iteris, Inc. Odetics currently owns 78.2% of the outstanding
+common stock of Iteris or 62.7% as calculated for the preferred stock conversion
+equivalent. Meyer, Mohaddes Associates, Inc. currently operates as a
+wholly-owned subsidiary of Iteris, Inc.
+In the early 1980s, we developed the technical expertise to apply
+automation to new commercial applications and established our Odetics Broadcast
+division. We incorporated our Odetics Broadcast division in 1999 as Broadcast,
+Inc. Broadcast is a supplier of content management and delivery solutions for
+the television, cable and satellite industries. The success of our video tape
+libraries led us to pursue new applications for information automation
+technologies. In 1991, we introduced an automated tape handling subsystem for
+integration into tape libraries designed for midrange computers and
+client/server networks. In January 1993, we formed a separate subsidiary, ATL
+Products, Inc., to pursue the market for automated tape libraries. In March
+1997, ATL completed an initial public offering of 1,650,000 shares of its Class
+A common stock. We distributed our remaining 82.9% interest in ATL to our
+stockholders in a tax-free distribution in October 1997.
+1
+Odetics has a unique mix of competencies in outdoor image processing,
+high-speed security processing, precision timing and synchronization, and data
+management. We have a unique identity within each of our vertical markets that
+we address, and our business is organizationally structured so that our
+management teams and technical competencies are in alignment with each area of
+market focus. Our business units share a common overhead structure for
+facilities, human resources, benefits and certain accounting, finance and
+management services.
+We currently define our business segments as video products, telecom
+products and ITS. Our video products segment includes our Broadcast subsidiary
+and our MAXxess subsidiary. Our telecom products segment consists of our Zyfer
+subsidiary. Our ITS segment consists of our Iteris subsidiary. For more
+information concerning our business segments, please see Note [14] of Notes to
+Consolidated Financial Statements.
+Video Products
+Broadcast, Inc.
+Broadcast is a supplier of content management and delivery solutions for
+the television, cable and satellite industries. Broadcast's systems automate the
+storage and scheduling of commercials, news stories and other television
+programming recorded on video server storage systems and videotape. We believe
+that enhanced operational efficiencies are a principal factor underlying the
+automation of broadcast television stations and satellite uplink operations as
+the industry transitions to digital television. The Broadcast product offering
+is based on proprietary software solutions for broadband video content
+management and delivery to serve broadcast and cable operations. The AIRO(TM)
+suite of products is Broadcast's content management and delivery solution that
+is designed to automate the on-air operations of television and cable
+broadcasters.
+Sales, Marketing and Principal Customers. Broadcast sells directly to
+broadcast television stations, satellite uplink operations, and other broadcast
+television and cable television system operators. The sales and marketing
+management for Broadcast is located at our principal facilities in Anaheim,
+California. Broadcast maintains a dedicated field sales force of four persons
+operating in four sales regions in North America, and two sales managers for
+Latin America and Europe. Broadcast also utilizes additional independent
+representative organizations to promote its products in various other foreign
+markets. During the year ended March 31, 2002, Broadcast implemented indirect
+sales channels consisting of system integrators, value added resellers and
+system distributors.
+The customers of Broadcast include major television networks such as Fox,
+Nickelodeon, CNBC, Televisa, Measat Broadcast Network Systems, NBC, the PBS
+Network, Group W Satellite Communications, Asia Broadcast Centre, Univision and
+over 250 independent and network-affiliated television stations. Broadcast
+currently has systems installed in over 40 countries.
+Manufacturing and Materials. Within our Anaheim facilities, Broadcast
+maintains a dedicated manufacturing operation as well as infrastructure to
+support production and inventory control, purchasing, quality assurance and
+manufacturing. Our AIRO products are serviced primarily in a facility located in
+Austin, Texas.
+Broadcast purchases video servers from Grass Valley Group, Leitch and
+Pinnacle Systems and purchases video switching, conversion and monitoring
+equipment from Grass Valley Group and Leitch. Broadcast also purchases cabinets
+and other fabricated parts and components from other third party suppliers.
+MAXxess Systems Inc.
+MAXxess Systems produces enterprise security management systems and
+electronic access control systems that meet the facility security needs of
+institutional, commercial, industrial and retail users. MAXxess sells a full
+line of electronic access control products consisting of software, hardware and
+digital video badging technologies. During the year ended March 31, 2002,
+MAXxess introduced its Environmental Security Systems that integrate its base
+AXxess 202 system with new detection technologies for toxic chemicals, gases and
+narcotics, in addition to video-based detection of smoke and unauthorized
+vehicles. MAXxess believes that its Environmental Security Systems provide
+enhanced levels of monitoring, control and detection that will be required in
+public facilities including buildings, airports, ports and for other high value
+assets.
+2
+Sales, Marketing and Principal Customers. MAXxess markets and sells its
+products globally through a network of system integrators. In the United States,
+MAXxess has three regional sales managers who oversee three geographical regions
+and manage the integrators. MAXxess operates a full service branch office in
+Windsor U.K. which serves the sales needs of the EMEA region. The Windsor office
+also provides local product availability and technical support for the region.
+Manufacturing and Materials. MAXxess maintains a dedicated manufacturing
+area located within our principal facilities in Anaheim, California. MAXxess
+maintains infrastructure to support production and inventory control,
+purchasing, quality assurance and manufacturing engineering at our Anaheim
+facilities.
+Telecom Products - Zyfer, Inc.
+Zyfer designs, develops and manufactures precision time and synchronization
+systems and products for network communications, computer networks and military
+command and control applications. Zyfer is under subcontract to provide NASA
+service support for space-borne digital data recorders. The space-borne digital
+recorders serviced by Zyfer used in on-board recording of flight systems for the
+U.S. Space Shuttle program.
+Zyfer's synchronization systems are based on GPS and oscillator
+technologies and are sold for applications in wireless networks and satellite
+communications for both commercial and government consumers. Significant
+customers of Zyfer include the U.S. government, government subcontractors and
+OEM suppliers to wireless carriers.
+Zyfer has developed a Gigabit network security processor called the
+SKP-100S. This product, anticipated to be the first of a family of products, is
+built around a proprietary network security processor technology called
+StealthKey. Typical applications are for network security, specifically storage
+area networks. Zyfer believes that the StealthKey technology has key performance
+advantages including automatic and transparent key generation, ease of
+implementation, and the ability to operate at wire speed.
+Sales, Marketing and Principal Customers. Zyfer conducts its selling and
+marketing activities directly from our principal facilities in Anaheim,
+California, and sells its synchronization products primarily through
+manufacturers' representatives.
+Manufacturing and Materials. Zyfer's manufacturing processes are ISO 9001
+certified. Most of its manufacturing processes consist of final assembly and
+test, which are conducted at our Anaheim, California facilities. Zyfer
+outsources board assembly and some preliminary fabrication processes.
+ITS Products - Iteris, Inc.
+Iteris, Inc. designs, develops, markets and implements sensors and systems
+for surface transportation. Using its proprietary software and ITS industry
+expertise, Iteris provides video sensor systems and transportation management
+and traveler information systems for the ITS industry. The ITS industry is
+comprised of companies applying a variety of technologies to enable the safe and
+efficient movement of people and goods. Iteris uses its outdoor image
+recognition software expertise to develop proprietary algorithms for video
+sensor systems that improve vehicle safety and the flow of traffic. Our
+knowledge of the ITS industry enables Iteris to design and implement
+transportation solutions that help public agencies reduce traffic congestion and
+provide greater access to traveler information.
+Iteris' proprietary image recognition systems include AutoVue and Vantage.
+AutoVue is a small windshield mounted sensor that utilizes proprietary software
+to detect and warn drivers of unintended lane departures. Iteris believes that
+AutoVue is a broad sensor platform that, through additional software
+development, may be expanded to incorporate additional safety and convenience
+features. Vantage is a video vehicle sensing system that detects the presence of
+vehicles at signalized intersections enabling a more efficient allocation of
+green signal time.
+Iteris' transportation management systems services business designs,
+develops and implements software-based systems that integrate sensors, video
+surveillance, computers and advanced communications equipment enabling public
+agencies to monitor, control and direct traffic flow, assist in the quick
+dispatch of emergency crews and distribute real-time information about traffic
+conditions.
+3
+Sales, Marketing and Principal Customers. Iteris markets and sells its
+transportation management systems and services directly to government agencies
+pursuant to negotiated contracts that involve competitive bidding and specific
+qualification requirements. Sales of Iteris' systems contracts generally involve
+long lead times and require extensive specification development, evaluation and
+price negotiations.
+Iteris sells its Vantage vehicle detection systems primarily through
+indirect sales channels comprised of independent dealers in the United States
+and Canada who sell integrated solutions and related products to the traffic
+intersection market. The independent dealers for Iteris are primarily
+responsible for sales, installation and support of Vantage systems. These
+dealers maintain an inventory of demonstration traffic products including the
+Vantage vehicle detection systems and sell directly to government agencies and
+installation contractors. These dealers often have long-term arrangements with
+the government agencies in their territory for the supply of various products
+for the construction and renovation of traffic intersections. Iteris holds
+technical training classes for its dealers and maintains a full-time staff of
+customer support technicians to provide technical assistance when needed.
+The marketing strategy for AutoVue is to establish it as the leading
+platform for in vehicle video sensing for trucks and passenger cars. AutoVue is
+sold directly by Iteris to vehicle manufacturers and major automotive suppliers.
+Iteris currently has a direct sales force for AutoVue consisting of two product
+managers. Product managers are supported by project and applications engineers
+who are responsible for applications and customer support.
+Manufacturing and Materials. Iteris designs, assembles and tests the
+components of its Vantage systems in approximately 6,000 square feet of space at
+our Anaheim facility. Production equipment consists of assembly lines and test
+apparatus for final assembly and testing of the manufactured product. Production
+volume is based upon quarterly forecasts that Iteris readjusts on a monthly
+basis to control inventory. Iteris subcontracts the manufacture of its AutoVue
+systems to one manufacturer. Iteris intends to engage additional manufacturers
+with expertise in high volume production to produce higher volumes for light and
+medium trucks and passenger cars. Iteris does not manufacture any of the
+hardware used in the transportation management and traveler information systems
+that it designs and implements. The production facility for Iteris is ISO 9001
+certified.
+Customer Support and Services
+Each of our business units is responsible for its own customer support and
+service organizations. We provide warranty service for each of our product
+lines, as well as follow-up service and support, for which we typically charge
+separately. We also offer separate software maintenance agreements to our
+customers. We view customer support services as a critical competitive factor as
+well as a revenue source.
+Backlog
+Our backlog of unfulfilled firm orders was approximately $42.7 million as
+of March 31, 2002 and was approximately $31.0 million as of March 31, 2001.
+Approximately 68% of our backlog at March 31, 2001 was recognized as revenues in
+the fiscal year ended March 31, 2002, and approximately 67% of our backlog at
+March 31, 2002 is expected to be recognized as revenues in the fiscal year ended
+March 31, 2003. Pursuant to the customary terms of our agreements with
+government contractors and other customers, customers can generally cancel or
+reschedule orders with little or no penalties. Lead times for the release of
+purchase orders depend upon the scheduling and forecasting practices of our
+individual customers, which also can affect the timing of the conversion of our
+backlog into revenues. For these reasons, among others, our backlog at a
+particular date may not be indicative of our future revenues.
+Product Development
+Each of our business units directs and staffs its own product development
+activities. Most of our development activities are conducted at our principal
+facilities in Anaheim, California. Our business units have historically required
+substantial ongoing research and development expenditures and other product
+development activities. Our company-sponsored research and development costs and
+expenses were approximately $13.0 million in fiscal 2000, $13.8 million in
+fiscal 2001 and $8.1 million in fiscal 2002. We expect to continue to pursue
+significant product development programs and incur significant research and
+development expenditures in each of our business units.
+4
+Competition
+Our business units generally face significant competition in each of their
+respective markets. Increased competition may result in price reductions,
+reduced gross margins and loss of market share, any of which could have a
+material adverse effect on our business, financial condition and results of
+operations.
+Broadcast's primary competitors include Sony, Harris, Encoda and Probel.
+Sony is a large, international supplier of extensive professional quality
+products. Harris and Probel principally provide automation control for video
+libraries and disk recorders. Broadcast's systems compete primarily in the arena
+of facility management and enterprise wide automation. We believe that the
+capability of our systems to integrate the broadcast station business systems
+acquisition processes, storage devices and presentation devices under a
+relational database management system represents a unique and differentiable
+capability.
+MAXxess principally competes with Casi-Rusco, Checkpoint, Cardkey, Lenel
+and Northern Computers in the sale of access control systems. MAXxess generally
+competes on the basis of its distributed processing system architecture, an open
+system that readily integrates other security subsystems and new detection
+capabilities, and a superior operator interface.
+Zyfer's primary competition for network synchronization products is Datum,
+Inc. and TrueTime Inc.
+While we believe that AutoVue is the only commercially-available lane
+departure warning system, potential competitors of Iteris include Delphi
+Automotive Systems Corporation domestically, NEC Corporation and Hitachi Ltd. in
+Japan and Robert Bosch Gmbh in Europe, which are currently developing video
+sensor technologies for the vehicle industry that could be used for lane
+departure warning systems. In the market for our Vantage vehicle detection
+systems, Iteris competes with manufacturers of both "above ground" video camera
+detection systems, such as Econolite Control Products, Inc., Trafficon, N.V. and
+the Peek Traffic Systems, and other non-intrusive detection devices including
+microwave, infrared, ultrasonic and magnetic detectors, as well as manufacturers
+and installers of in-pavement inductive loop products.
+The transportation management and traveler information systems market is
+highly fragmented and is subject to evolving national and regional quality and
+safety standards. Iteris' competitors vary in number, scope and breadth of the
+products and services they offer. Iteris' competitors in advanced transportation
+management and traveler information systems include corporations such as
+Transcore, Lockheed Martin Corporation, PB Farradyne Inc., Kimley-Horn and
+Associates, Inc. and National Engineering Technology, Inc. Iteris' competitors
+in transportation engineering, planning and design include major firms such as
+Parsons Brinkerhoff, Inc. and Parsons Transportation Group Inc., as well as many
+regional engineering firms.
+In general, the markets for the products and services offered by our
+businesses are highly competitive and are characterized by rapidly changing
+technology and evolving standards. Many of our current and prospective
+competitors have longer operating histories, greater name recognition, access to
+larger customer bases and significantly greater financial, technical,
+manufacturing, distribution and marketing resources than us. As a result, they
+may be able to adapt more quickly to new or emerging standards or technologies
+or to devote greater resources to the promotion and sale of their products. It
+is also possible that new competitors or alliances among competitors could
+emerge and rapidly acquire significant market share. We believe that our ability
+to compete effectively in our target markets depends on a number of factors,
+including the success and timing of our new product development, the
+compatibility of our products with a broad range of computing systems, product
+quality and performance, reliability, functionality, price, and service and
+technical support. Our failure to provide services and develop and market
+products that compete successfully with those of other suppliers and consultants
+in our target markets would have a material adverse effect on our business,
+financial condition and results of operations.
+Intellectual Property and Proprietary Rights
+Our ability to compete effectively depends in part on our ability to
+develop and maintain the proprietary aspects of our technology. Our policy is to
+obtain appropriate proprietary rights protection for any potentially significant
+new technology acquired or developed each of our business units. We currently
+hold a number of United States and foreign patents and trademarks, which will
+expire at various dates commencing in 2004. We also have pending a number of
+United States and foreign patent applications relating to certain of our
+products; however, we cannot be certain that any patents will be granted
+pursuant to these applications.
+5
+In addition to patent laws, we rely on copyright and trade secret laws to
+protect our proprietary rights. We attempt to protect our trade secrets and
+other proprietary information through agreements with customers and suppliers,
+proprietary information agreements with our employees and consultants, and other
+similar measures. We cannot be certain that we will be successful in protecting
+our proprietary rights. While we believe our patents, patent applications,
+software and other proprietary know-how have value, changing technology makes
+our future success dependent principally upon our employees' technical
+competence and creative skills for continuing innovation.
+Litigation has been necessary in the past and may be necessary in the
+future to enforce our proprietary rights, to determine the validity and scope of
+the proprietary rights of others, or to defend us against claims of infringement
+or invalidity by others. An adverse outcome in such litigation or similar
+proceedings could subject us to significant liabilities to third parties,
+require disputed rights to be licensed from others or require us to cease
+marketing or using certain products, any of which could have a material adverse
+effect on our business, financial condition and results of operations. In
+addition, the cost of addressing any intellectual property litigation claim,
+both in legal fees and expenses, as well as from the diversion of management's
+resources, regardless of whether the claim is valid, could be significant and
+could have a material adverse effect on our business, financial condition and
+results of operations.
+Employees
+We refer to our employees as associates. As of June 17, 2002, Odetics and
+its subsidiaries employed an aggregate of 315 associates, including 77
+associates in general management, administration and finance; 36 associates in
+sales and marketing; 132 associates in product development; 58 associates in
+operations, manufacturing and quality; and 12 associates in customer service.
+None of our associates are represented by a labor union, and we have never
+experienced a work stoppage.
+We provide centralized support for human resources management for each of
+our business units and subsidiaries. These services include recruiting,
+administration and outplacement.
+Government Regulation
+Our manufacturing operations are subject to various federal, state and
+local laws, including those restricting the discharge of materials into the
+environment. We are not involved in any pending or threatened proceedings which
+would require curtailment of our operations because of such regulations. We
+continue to expend funds in connection with our compliance with applicable
+environmental regulations. These expenditures have not, however, been
+significant in the past, and we do not expect any significant expenditures in
+the near future.
+From time to time, a portion of our work relating to network
+synchronization systems may constitute classified United States government
+information or may be used in classified programs of the United States
+Government. For this purpose, we possess certain relevant security clearances.
+Our affected facilities and operations are also subject to security regulations
+of the United States Government. We believe we are currently in full compliance
+with these regulations.
+6
+RISK FACTORS
+Before deciding to invest in Odetics or to maintain or increase your
+investment, you should carefully consider the risks described below, in addition
+to the other information contained in this report and in our other filings with
+the SEC, including our reports on Forms 10-Q and 8-K. The risks and
+uncertainties described below are not the only ones facing us. Additional risks
+and uncertainties not presently known to us or that we currently deem immaterial
+may also affect our business operations. If any of these risks actually occur,
+our business, financial condition or results of operations could be seriously
+harmed. In that event, the market price for our common stock could decline and
+you may lose all or part of your investment.
+We Have Experienced Substantial Losses and Expect Future Losses. We
+experienced operating losses of $10.8 million the year ended March 31, 2002,
+$37.9 million for the year ended March 31, 2001 and $32.9 million for the year
+ended March 31, 2000. In the quarter ended September 30, 2001, we downsized our
+business in connection with our sale of the Gyyr CCTV Products division and the
+discontinuation of the business of our Mariner Networks subsidiary and the
+reorganization of our European operations. We cannot assure you that our efforts
+to downsize our operations will improve our financial performance, or that we
+will be able to achieve profitability on a quarterly or annual basis in the
+future. Most of our expenses are fixed in advance, and we generally are unable
+to reduce our expenses significantly in the short-term to compensate for any
+unexpected delay or decrease in anticipated revenues. As a result, we may
+continue to experience losses, which would make it difficult to fund our
+operations and achieve our business plan, and could cause the market price of
+our common stock to decline.
+We Will Need to Raise Additional Capital in the Future and May Not Be Able
+to Secure Adequate Funds on Terms Acceptable to Us, or at All. We have generated
+significant net losses in recent periods, and have experienced negative cash
+flows from operations in the amount of $18.2 million for the year ended March
+31, 2002 and $20.1 million for the year ended March 31, 2001. Although we
+completed the sale of our Anaheim, California property in May 2002, the majority
+of the proceeds of such sale were used to repay outstanding short-term
+indebtedness. We anticipate that we will need to raise additional capital in the
+future. Our Iteris subsidiary currently maintains a line of credit with a
+maximum availability of $5.0 million, which expires in August 2004.
+Substantially all of the assets of Iteris have been pledged to the lender to
+secure the outstanding indebtedness under this facility (although there were no
+amounts outstanding under the line of credit at June 21, 2002). Even though we
+retired the Odetics line of credit in the quarter ended December 31, 2001, we
+also incurred cash obligations in the amount of $3.0 million payable over the
+next seven months related to the discontinuation of Mariner Networks and the
+reorganization of our European operations. We plan to raise additional capital
+in the near future, either through bank borrowings, other debt or equity
+financings, or the divestiture of business units or select assets. We cannot
+assure you that any additional capital will be available on a timely basis, on
+acceptable terms, or at all. These conditions, together with our recurring
+losses and cash requirements, raise substantial doubt about our ability to
+continue as a going concern.
+Our capital requirements will depend on many factors, including:
+. our ability to control costs;
+. market acceptance of our products and the overall level of sales of our
+products;
+. our ability to generate operating income;
+. increased research and development funding, and required investments in
+our business units;
+. increased sales and marketing expenses;
+. technological advancements and our competitors' response to our
+products;
+. capital improvements to new and existing facilities;
+. potential acquisitions of businesses and product lines;
+. our relationships with customers and suppliers; and
+7
+. general economic conditions including the effects of the current
+economic slowdown and international conflicts.
+If our capital requirements are materially different from those currently
+planned, we may need additional capital sooner than anticipated. If additional
+funds are raised through the issuance of equity or convertible debt securities,
+the percentage ownership of our stockholders will be reduced and such securities
+may have rights, preferences and privileges senior to our common stock.
+Additional financing may not be available on favorable terms or at all. If
+adequate funds are not available or are not available on acceptable terms, we
+may be unable to continue our operations as planned, develop or enhance our
+products, expand our sales and marketing programs, take advantage of future
+opportunities or respond to competitive pressures.
+The Trading Price of Our Common Stock Is Volatile. The trading price of our
+common stock has been subject to wide fluctuations in the past. Since January
+2000, our common stock has traded at prices as low as $1.27 per share and as
+high as $29.44 per share. In April 2002, because we failed to meet the minimum
+stockholder's equity requirement for continued listing on the Nasdaq National
+Market, both our Class A common stock and Class B common stock were delisted
+from the Nasdaq National Market and subsequently approved for listing on the
+Nasdaq SmallCap Market. If our stock price continues to decline or declines
+below $1.00 per share for a period of time, our common stock could be subject to
+delisting from the Nasdaq SmallCap Market and there may not be a market for our
+stock. We may not be able to increase or sustain the current market price of our
+common stock in the future. As such, you may not be able to resell your shares
+of common stock at or above the price you paid for them. The market price of our
+common stock could continue to fluctuate in the future in response to various
+factors, including, but not limited to:
+. quarterly variations in operating results;
+. our ability to control costs and improve cash flow;
+. shortages announced by suppliers;
+. announcements of technological innovations or new products by our
+competitors, customers or us;
+. acquisitions or businesses, products or technologies;
+. changes in pending litigation or new litigation;
+. changes in investor perceptions;
+. our ability to spin-off any business unit;
+. applications or product enhancements by us or by our competitors; and
+. changes in earnings estimates or investment recommendations by
+securities analysts.
+The stock market in general has recently experienced volatility, which has
+particularly affected the market prices of equity securities of many high
+technology companies. This volatility has often been unrelated to the operating
+performance of these companies. These broad market fluctuations may adversely
+affect the market price of our common stock. In the past, companies that have
+experienced volatility in the market price of their securities have been the
+subject of securities class action litigation. If we were to become the subject
+of a class action lawsuit, it could result in substantial losses and divert
+management's attention and resources from other matters.
+We Depend on Government Contracts and Subcontracts and Face Additional
+Risks Related to Fixed Price Contracts. A significant portion of the sales by
+Iteris and a portion of our sales by Zyfer were derived from contracts with
+governmental agencies, either as a general contractor, subcontractor or
+supplier. Government contracts represented approximately 24%, 26% and 38% of our
+total net sales and contract revenues for the years ended March 31, 2000, 2001
+and 2002, respectively. We anticipate that revenue from government contracts
+will continue to increase in the near future. Government business is, in
+general, subject to special risks and challenges, including:
+8
+. long purchase cycles or approval processes;
+. competitive bidding and qualification requirements;
+. performance bond requirements;
+. changes in government policies and political agendas;
+. delays in funding, budgetary constraints and cut-backs; and
+. milestone requirements and liquidated damage provisions for failure to
+meet contract milestones.
+In addition, a large number of our government contracts are fixed price
+contracts. As a result, we may not be able to recover for any cost overruns.
+These fixed price contracts require us to estimate the total project cost based
+on preliminary projections of the project's requirements. The financial
+viability of any given project depends in large part on our ability to estimate
+these costs accurately and complete the project on a timely basis. In the event
+our costs on these projects exceed the fixed contractual amount, we will be
+required to bear the excess costs. These additional costs adversely affect our
+financial condition and results of operations. Moreover, certain of our
+government contracts are subject to termination or renegotiation at the
+convenience of the government, which could result in a large decline in our net
+sales in any given quarter. Our inability to address any of the foregoing
+concerns or the loss or renegotiation of any material government contract could
+seriously harm our business, financial condition and results of operations.
+We are Exposed to the Risks Associated with the Recent Worldwide Economic
+Slowdown and Related Uncertainties. Concerns about inflation, decreased consumer
+confidence, reduced corporate profits and capital spending, and recent
+international conflicts and terrorist and military actions have resulted in a
+downturn in worldwide economic conditions, particularly in the United States. As
+a result of these unfavorable economic conditions, we have experienced a
+slowdown in customer orders, cancellations and rescheduling of backlog and
+higher overhead costs. In addition, recent political and social turmoil related
+to international conflicts and terrorist acts can be expected to put further
+pressure on economic conditions in the U.S. and worldwide. These political,
+social and economic conditions make it extremely difficult for our customers,
+our suppliers and us to accurately forecast and plan future business activities.
+If such conditions continue or worsen, our business, financial condition and
+results of operations will likely be materially and adversely affected.
+Our Quarterly Operating Results Fluctuate as a Result of Many Factors. Our
+quarterly revenues and operating results have fluctuated and are likely to
+continue to vary from quarter to quarter due to a number of factors, many of
+which are not within our control. Factors that could affect our revenues
+include, among others, the following:
+. our ability to raise additional capital;
+. our significant investment in research and development for our
+subsidiaries and business units;
+. our ability to control costs;
+. international conflicts and acts of terrorism;
+. our ability to develop, introduce, market and gain market acceptance of
+new products applications and product enhancements in a timely manner;
+. the size, timing, rescheduling or cancellation of significant customer
+orders;
+. the introduction of new products by competitors;
+. the availability of components used in the manufacture of our products;
+. changes in our pricing policies and the pricing policies by our
+suppliers and competitors, pricing concessions on volume sales, as well
+as increased price competition in general;
+9
+. the long lead times associated with government contracts or required by
+vehicle manufacturers;
+. our success in expanding and implementing our sales and marketing
+programs;
+. the effects of technological changes in our target markets;
+. our relatively small level of backlog at any given time;
+. the mix of sales among our business units;
+. deferrals of customer orders in anticipation of new products,
+applications or product enhancements;
+. the risks inherent in our acquisitions of technologies and businesses;
+. risks and uncertainties associated with our international business;
+. currency fluctuations and our ability to get currency out of certain
+foreign countries; and
+. general economic and political conditions.
+In addition, our sales in any quarter may consist of a relatively small
+number of large customer orders. As a result, the timing of a small number of
+orders may impact our quarter-to-quarter results. The loss of or a substantial
+reduction in orders from any significant customer could seriously harm our
+business, financial condition and results of operations.
+Due to all of the factors listed above and other risks discussed in this
+report, our future operating results could be below the expectations of
+securities analysts or investors. If that happens, the trading price of our
+common stock could decline. As a result of these quarterly variations, you
+should not rely on quarter-to-quarter comparisons of our operating results as an
+indication of our future performance.
+Our Operating Strategy for Developing Companies is Expensive and May Not Be
+Successful. Our business strategy historically has required us to make
+significant investments in our business units. These investments are expensive
+and require the commitment of significant time and resources. We expect to
+continue to invest in the development of certain of our business units with the
+goal of achieving profitability in each of our business units, and to a lesser
+extent, to monetize those business units for the benefit of our stockholders
+through an initial public offering, spin-off or sale to a strategic buyer. We
+may not recognize the benefits of this investment for a significant period of
+time, if at all. Our ability to achieve profitability in any business unit, to
+complete any private or public offerings of securities by any of our business
+units, and/or to spin-off our interest in the business unit to our stockholders
+will depend upon many factors, including:
+. the overall performance and results of operations of the particular
+business unit;
+. the potential market for our business unit;
+. our ability to assemble and retain a qualified management team for the
+business unit;
+. our financial position and cash requirements;
+. the business unit's customer base and product line;
+. the current tax treatment of spin-off and sale transactions, and our
+ability to obtain favorable determination letters from the Internal
+Revenue Service; and
+. general economic and market conditions, including the receptiveness of
+the stock markets to initial public offerings and private placements.
+We may not be able to achieve profitability in our business units, to
+complete a successful private or public offering or to spin-off of any of our
+business units in the near future, or at all. During fiscal 2001, we attempted
+to complete the initial public offering of Iteris, but withdrew the offering due
+to adverse market conditions. Even if we
+10
+are able to achieve profitability and the market is receptive to public
+offerings, we may decide not to complete any further offerings, spin-off a
+particular business unit, or delay the spin-off until a later date.
+We Must Keep Pace with Rapid Technological Change to Remain Competitive.
+Our target markets are in general characterized by the following factors:
+. rapid technological advances;
+. downward price pressure in the marketplace as technologies mature;
+. changes in customer requirements;
+. frequent new product introductions and enhancements; and
+. evolving industry standards and changes in the regulatory environment.
+Our future success will depend upon our ability to anticipate and adapt to
+changes in technology and industry standards, and to effectively develop,
+introduce, market and gain broad acceptance of new products and product
+enhancements incorporating the latest technological advancements.
+We believe that we must continue to make substantial investments to support
+ongoing research and development in order to remain competitive. We need to
+continue to develop and introduce new products that incorporate the latest
+technological advancements in hardware, storage media, operating system software
+and applications software in response to evolving customer requirements. Our
+business and results of operations could be adversely affected if we do not
+anticipate or respond adequately to technological developments or changing
+customer requirements. We cannot assure you that any such investments in
+research and development will lead to any corresponding increase in revenue.
+Our Future Success Depends on the Successful Development and Market
+Acceptance of New Products. We believe our revenue growth and future operating
+results will depend on our ability to complete development of new products and
+enhancements, introduce these products in a timely, cost-effective manner,
+achieve broad market acceptance of these products and enhancements, and reduce
+our product costs. We may not be able to introduce any new products or any
+enhancements to our existing products on a timely basis, or at all. In addition,
+the introduction of any new products could adversely affect the sales of our
+certain of our existing products.
+Our future success will also depend in part on the success of several
+recently introduced products including CommSync II, a Zyfer solution for secure,
+high speed, point-to-point communications; AutoVue, our lane departure warning
+system; and AIRO 9.0, our broadcast automation solution. Market acceptance of
+our new products depends upon many factors, including our ability to accurately
+predict market requirements and evolving industry standards, our ability to
+resolve technical challenges in a timely and cost-effective manner and achieve
+manufacturing efficiencies, the perceived advantages of our new products over
+traditional products and the marketing capabilities of our independent
+distributors and strategic partners. Our business and results of operations
+could be seriously harmed by any significant delays in our new product
+development. Certain of our new products could contain undetected design faults
+and software errors or "bugs" when first released by us, despite our testing. We
+may not discover these faults or errors until after a product has been installed
+and used by our customers. Any faults or errors in our existing products or in
+any new products may cause delays in product introduction and shipments, require
+design modifications or harm customer relationships, any of which could
+adversely affect our business and competitive position.
+Iteris currently outsources the manufacture of its AutoVue product line to
+a single manufacturer. This manufacturer may not be able to produce sufficient
+quantities of this product in a timely manner or at a reasonable cost, which
+could materially and adversely affect our ability to launch or gain market
+acceptance of AutoVue.
+We Have Significant International Sales and Are Subject to Risks Associated
+with Operating in International Markets. International sales represented 10% of
+our net sales and contract revenues for the fiscal year ended March 31, 2002,
+20% for the fiscal year ended March 31, 2001, and 20% for the fiscal year ended
+March 31, 2000. During the fiscal year ended March 31, 2002, we reorganized our
+European operations, which included the discontinuation of our Odetics Europe
+Ltd., MAXxess Europe Ltd., Mariner France and Mariner Europe Ltd.
+11
+operations, and the transition of our Broadcast and MAXxess international
+operations to branch office operations with the intent of lowering our
+international costs. This reorganization may result in significantly lower
+international sales in future periods and unanticipated liabilities related to
+the closures and we may not achieve the anticipated cost savings. We may also
+face challenges in managing and transitioning our international operations due
+to our limited experience operating through branch offices. In addition, the
+recent terrorist attacks in the United States and heightened security may
+adversely impact our international sales and could make our international
+operations more expensive.
+International business operations are also subject to other inherent risks,
+including, among others:
+. unexpected changes in regulatory requirements, tariffs and other trade
+barriers or restrictions;
+. longer accounts receivable payment cycles;
+. difficulties in managing and staffing international operations;
+. potentially adverse tax consequences;
+. the burdens of compliance with a wide variety of foreign laws;
+. import and export license requirements and restrictions of the United
+States and each other country in which we operate;
+. exposure to different legal standards and reduced protection for
+intellectual property rights in some countries;
+. currency fluctuations and restrictions; and
+. political, social and economic instability.
+We believe that international sales will continue to represent a
+significant portion of our revenues, and that continued growth and profitability
+may require further expansion of our international operations. Nearly all of our
+international sales from this point on are denominated in U.S. dollars. As a
+result, an increase in the relative value of the dollar could make our products
+more expensive and potentially less price competitive in international markets.
+We do not engage in any transactions as a hedge against risks of loss due to
+foreign currency fluctuations.
+Any of the factors mentioned above may adversely effect our future
+international sales and, consequently, effect our business, financial condition
+and operating results. Furthermore, as we increase our international sales, our
+total revenues may also be affected to a greater extent by seasonal fluctuations
+resulting from lower sales that typically occur during the summer months in
+Europe and other parts of the world.
+We Need to Manage Operations and the Integration of Our Acquisitions. Over
+the past few years, we have expanded our operations and made several substantial
+acquisitions of diverse businesses, including Intelligent Controls, Inc.,
+International Media Integration Services, Ltd., Meyer Mohaddes Associates, Inc.,
+Viggen Corporation, and certain assets of the Transportation Systems business of
+Rockwell International. We may engage in acquisitions of complementary
+businesses, products and technologies. Acquisitions may require significant
+capital infusions and, in general, acquisitions also involve a number of special
+risks, including:
+. potential disruption of our ongoing business and the diversion of our
+resources and management's attention;
+. the failure to retain or integrate key acquired personnel;
+. the challenge of assimilating diverse business cultures, and the
+difficulties in integrating the operations, technologies and
+information system of the acquired companies;
+. increased costs to improve managerial, operational, financial and
+administrative systems and to eliminate duplicative services;
+12
+. the incurrence of unforeseen obligations or liabilities;
+. potential impairment of relationships with employees or customers as a
+result of changes in management; and
+. increased interest expense and amortization of acquired intangible
+assets.
+Acquisitions may also materially and adversely affect our operating results
+due to large write-offs, contingent liabilities, substantial depreciation,
+deferred compensation charges or goodwill amortization, or other adverse tax or
+audit consequences. Our failure to manage growth and integrate our acquisitions
+successfully could adversely affect our business, financial condition and
+results of operations.
+Our competitors are also soliciting potential acquisition candidates, which
+could both increase the price of any acquisition targets and decrease the number
+of attractive companies available for acquisition. We cannot assure you that we
+will be able to consummate any additional acquisitions, successfully integrate
+any acquisitions or realize the benefits anticipated from any acquisition.
+The Markets in Which We Operate Are Highly Competitive and Have Many More
+Established Competitors. We compete with numerous other companies in our target
+markets and we expect such competition to increase due to technological
+advancements, industry consolidations and reduced barriers to entry. Increased
+competition is likely to result in price reductions, reduced gross margins and
+loss of market share, any of which could seriously harm our business, financial
+condition and results of operations. Many of our competitors have far greater
+name recognition and greater financial, technological, marketing and customer
+service resources than we do. This may allow them to respond more quickly to new
+or emerging technologies and changes in customer requirements. It may also allow
+them to devote greater resources to the development, promotion, sale and support
+of their products than we can. Recent consolidations of end users, distributors
+and manufacturers in our target markets have exacerbated this problem. As a
+result of the foregoing factors, we may not be able to compete effectively in
+our target markets and competitive pressures could adversely affect our
+business, financial condition and results of operations.
+We Cannot Be Certain of Our Ability to Attract and Retain Key Personnel and
+We Do Not Have Employment Agreements with Any Key Personnel. Due to the
+specialized nature of our business, we are highly dependent on the continued
+service of our executive officers and other key management, engineering and
+technical personnel, particularly Joel Slutzky, our Chairman of the Board, who
+recently retired as our Chief Executive Officer, and Gregory A. Miner, our Chief
+Executive Officer and Chief Financial Officer. The leadership transition between
+Mr. Slutzky and Mr. Miner could adversely affect our business. We do not have
+any employment contracts with any of our officers or key employees. The loss of
+any of these individuals could adversely affect our business, financial
+condition or results of operations.
+Our success will also depend in large part upon our ability to continue to
+attract, retain and motivate qualified engineering and other highly skilled
+technical personnel. Competition for employees, particularly development
+engineers, is intense. We may not be able to continue to attract and retain
+sufficient numbers of such highly skilled employees. Our inability to attract
+and retain additional key employees or the loss of one or more of our current
+key employees could adversely affect upon our business, financial condition and
+results of operations.
+We May Not be Able to Adequately Protect or Enforce Our Intellectual
+Property Rights. If we are not able to adequately protect or enforce the
+proprietary aspects of our technology, competitors could be able to access our
+proprietary technology and our business, financial condition and results of
+operations will likely be seriously harmed. We currently attempt to protect our
+technology through a combination of patent, copyright, trademark and trade
+secret laws, employee and third party nondisclosure agreements and similar
+means. Despite our efforts, other parties may attempt to disclose, obtain or use
+our technologies or solutions. Our competitors may also be able to independently
+develop products that are substantially equivalent or superior to our products
+or design around our patents. In addition, the laws of some foreign countries do
+not protect our proprietary rights as fully as do the laws of the United States.
+As a result, we may not be able to protect our proprietary rights adequately in
+the United States or abroad.
+From time to time, we have received notices that claim we have infringed
+upon the intellectual property of others. Even if these claims are not valid,
+they could subject us to significant costs. We have engaged in litigation in the
+past, and litigation may be necessary in the future to enforce our intellectual
+property rights or to determine
+13
+the validity and scope of the proprietary rights of others. Litigation may also
+be necessary to defend against claims of infringement or invalidity by others.
+An adverse outcome in litigation or any similar proceedings could subject us to
+significant liabilities to third parties, require us to license disputed rights
+from others or require us to cease marketing or using certain products or
+technologies. We may not be able to obtain any licenses on terms acceptable to
+us, or at all. We also may have to indemnify certain customers or strategic
+partners if it is determined that we have infringed upon or misappropriated
+another party's intellectual property. Any of these results could adversely
+affect on our business, financial condition and results of operations. In
+addition, the cost of addressing any intellectual property litigation claim,
+both in legal fees and expenses, and the diversion of management resources,
+regardless of whether the claim is valid, could be significant and could
+seriously harm our business, financial condition and results of operations.
+We Are Controlled by Certain of Our Officers and Directors. As of June 21,
+2002, our officers and directors beneficially owned approximately 24% of the
+total combined voting power of the outstanding shares of our Class A common
+stock and Class B common stock. As a result of their stock ownership, our
+management will be able to significantly influence the election of our directors
+and the outcome of corporate actions requiring stockholder approval, such as
+mergers and acquisitions, regardless of how our other stockholders may vote.
+This concentration of voting control may have a significant effect in delaying,
+deferring or preventing a change in our management or change in control and may
+adversely affect the voting or other rights of other holders of common stock.
+Our Stock Structure and Certain Anti-Takeover Provisions May Affect the
+Price of Our Common Stock. Certain provisions of our certificate of
+incorporation and our stockholder rights plan could make it difficult for a
+third party to acquire us, even though an acquisition might be beneficial to our
+stockholders. These provisions could limit the price that investors might be
+willing to pay in the future for shares of our common stock. Our Class A common
+stock entitles the holder to one-tenth of one vote per share and our Class B
+common stock entitles the holder to one vote per share. The disparity in the
+voting rights between our common stock, as well as our insiders' significant
+ownership of the Class B common stock, could discourage a proxy contest or make
+it more difficult for a third party to effect a change in our management and
+control. In addition, our Board of Directors is authorized to issue, without
+stockholder approval, up to 2,000,000 shares of preferred stock with voting,
+conversion and other rights and preferences superior to those of our common
+stock, as well as additional shares of Class B common stock. Our future issuance
+of preferred stock or Class B common stock could be used to discourage an
+unsolicited acquisition proposal.
+In March 1998, we adopted a stockholder rights plan and declared a dividend
+of preferred stock purchase rights to our stockholders. In the event a third
+party acquires more than 15% of the outstanding voting control of our company or
+15% of our outstanding common stock, the holders of these rights will be able to
+purchase the junior participating preferred stock at a substantial discount off
+of the then current market price. The exercise of these rights and purchase of a
+significant amount of stock at below market prices could cause substantial
+dilution to a particular acquiror and discourage the acquiror from pursuing our
+company. The mere existence of a stockholder rights plan often delays or makes a
+merger, tender offer or proxy contest more difficult.
+We Do Not Pay Cash Dividends. We have never paid cash dividends on our
+common stock and do not anticipate paying any cash dividends on either class of
+our common stock in the foreseeable future.
+We May Be Subject to Additional Risks. The risks and uncertainties
+described above are not the only ones facing our company. Additional risks and
+uncertainties not presently known to us or that we currently deem immaterial may
+also adversely affect our business operations.
\ No newline at end of file
diff --git a/raw/filings/0000350868/2001/0001017062-02-001321/item13.txt b/raw/filings/0000350868/2001/0001017062-02-001321/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..153e39cba7e326b96f4d4f3730e0cdef1122d1d8
--- /dev/null
+++ b/raw/filings/0000350868/2001/0001017062-02-001321/item13.txt
@@ -0,0 +1,3 @@
+ITEM 13. CERTAIN TRANSACTIONS
+The information under the caption "Certain Transactions," appearing in our
+proxy statement, is incorporated herein by reference.
\ No newline at end of file
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index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000350868/2001/0001017062-02-001321/rp_note.txt b/raw/filings/0000350868/2001/0001017062-02-001321/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000350868/2001/0001017062-02-001321/rpt_disclosure.txt b/raw/filings/0000350868/2001/0001017062-02-001321/rpt_disclosure.txt
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+10-K
+1
+a07-16543_110k.htm
+10-K
+UNITED
+STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington,
+D.C. 20549 
+FORM 10-K 
+(Mark One) 
+x 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR
+15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the
+fiscal year ended March 31, 2007 
+OR 
+o 
+TRANSITION REPORT PURSUANT TO SECTION 13 OR
+15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the
+transition period from 
+to 
+Commission
+file number 001-08762 
+ITERIS,
+INC. 
+(Exact Name of Registrant
+as Specified in Its Charter) 
+Delaware 
+95-2588496 
+(State or Other
+Jurisdiction 
+of Incorporation or Organization) 
+(I.R.S. Employer 
+Identification No.) 
+1515
+South Manchester Avenue, Anaheim, California 92802 
+(Address of
+Principal Executive Offices) (Zip Code) 
+Registrant’s
+Telephone Number, Including Area Code: (714)
+774-5000 
+Securities
+registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Name of each exchange on which registered 
+Common Stock, $0.10
+par value 
+American Stock
+Exchange 
+Securities
+registered pursuant to Section 12(g) of the Act: None 
+Indicate by check mark if the
+registrant is a well-known seasoned issuer, as defined in Rule 405 of the
+Securities Act. Yes o No x 
+Indicate by check mark if the
+registrant is not required to file reports pursuant to Section 13 or
+Section 15(d) of the Act. Yes o No x 
+Indicate by check mark
+whether the registrant (1) has filed all reports required to be filed by
+Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
+preceding 12 months (or for such shorter period that the registrant was
+required to file such reports), and (2) has been subject to such filing
+requirements for the past 90 days. Yes x No o 
+Indicate by a check mark if
+disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not
+contained herein, and will not be contained, to the best of registrant’s
+knowledge, in definitive proxy or information statements incorporated by
+reference in Part III of this Form 10-K or any amendment to
+this Form 10-K. o 
+Indicate by check mark
+whether the registrant is a large accelerated filer, an accelerated filer, or a
+non-accelerated filer. See definition of “accelerated filer and large
+accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one): 
+Large
+accelerated filer o Accelerated
+filer o Non-accelerated
+filer x 
+Indicate by check mark
+whether the registrant is a shell company (as defined in Exchange Act
+Rule 12b-2). Yes o No x 
+Based on the closing sale
+price of the registrant’s common stock on September 30, 2006, the last
+business day of the registrant’s most recently completed second fiscal quarter,
+the aggregate market value of the voting common stock held by nonaffiliates of
+the registrant was $54,700,000. For the purposes of this calculation, shares
+owned by officers, directors and 10% stockholders known to the registrant have
+been deemed to be owned by affiliates. This determination of affiliate status
+is not necessarily a conclusive determination for other purposes. 
+As of June 18, 2007,
+there were 32,575,330 shares of common stock outstanding. 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Part III incorporates by reference
+certain information from the registrant’s definitive proxy statement for the
+2007 Annual Meeting of Stockholders, which will be filed with the Securities
+and Exchange Commission not later than 120 days after the end of the fiscal
+year ended March 31, 2007. Except with respect to information specifically
+incorporated by reference in this report, the registrant’s proxy statement is
+not deemed to be filed as a part hereof. 
+ITERIS,
+INC. 
+ANNUAL
+REPORT ON FORM 10-K 
+FOR THE
+FISCAL YEAR ENDED MARCH 31, 2007 
+TABLE OF CONTENTS 
+PART I 
+ITEM
+1. 
+BUSINESS 
+ITEM
+1A. 
+RISK
+FACTORS 
+ITEM 1B. 
+UNRESOLVED STAFF
+COMMENTS 
+ITEM
+2. 
+PROPERTIES 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+ITEM 4. 
+SUBMISSION OF
+MATTERS TO A VOTE OF SECURITY HOLDERS 
+PART II 
+ITEM 5. 
+MARKET FOR
+REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES
+OF EQUITY SECURITIES 
+ITEM 6. 
+SELECTED
+CONSOLIDATED FINANCIAL DATA 
+ITEM 7. 
+MANAGEMENT’S
+DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+ITEM 7A. 
+QUANTITATIVE
+AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
+ITEM 8. 
+FINANCIAL
+STATEMENTS AND SUPPLEMENTARY DATA 
+ITEM 9. 
+CHANGES IN AND
+DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+ITEM 9A. 
+CONTROLS AND
+PROCEDURES 
+ITEM 9B. 
+OTHER INFORMATION 
+PART III 
+ITEM 10. 
+DIRECTORS,
+EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+ITEM 11. 
+EXECUTIVE
+COMPENSATION 
+ITEM 12. 
+SECURITY
+OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
+MATTERS 
+ITEM 13. 
+CERTAIN
+RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+ITEM 14. 
+PRINCIPAL
+ACCOUNTING FEES AND SERVICES 
+PART IV 
+ITEM 15. 
+EXHIBITS AND
+FINANCIAL STATEMENT SCHEDULES 
+Unless
+otherwise indicated in this report, the “registrant,” “we,” “us” and “our”
+collectively refers to Iteris, Inc. (formerly known as Iteris
+Holdings, Inc. and Odetics, Inc.) and its former subsidiary, Meyer,
+Mohaddes Associates, Inc., which was dissolved effective April 3,
+2006. 
+AutoVue®, Iteris® and Vantage® are among the
+registered trademarks of Iteris, Inc. Any other trademarks or trade names
+mentioned herein are the property of their respective owners. 
+2 
+Cautionary Statement 
+This report, including the following discussion and
+analysis, contains forward-looking statements (within the meaning of the
+Private Securities Litigation Reform Act of 1995) that are based on our current
+expectations, estimates and projections about our business and our industry,
+and reflect management’s beliefs and certain assumptions made by us based upon
+information available to us as of the date of this report. When used in this
+report and the information incorporated herein by reference, the words “expect(s),”
+“feel(s),” “believe(s),” “should,” “will,” “may,” “anticipate(s),” “estimate(s)”
+and similar expressions or variations of these words are intended to identify
+forward-looking statements. These forward-looking statements include but are
+not limited to statements regarding our anticipated sales, revenue, expenses,
+profits, capital needs, competition, backlog and manufacturing capabilities,
+the practical market applications, future applications and acceptance of our
+products and services, the status of our facilities and product development.
+These statements are not guarantees of future performance and are subject to
+certain risks and uncertainties which could cause actual results to differ
+materially from those projected. You should not place undue reliance on these
+forward-looking statements that speak only as of the date hereof. We undertake
+no obligation to republish revised forward-looking statements to reflect events
+or circumstances after the date hereof or to reflect the occurrence of
+unanticipated events. We encourage you to carefully review and consider the
+various disclosures made by us which describe certain factors which could
+affect our business, including those in “ Risk Factors”
+in Item 1A of this report, before deciding to invest in our company or to
+maintain or increase your investment. We undertake no obligation to revise or
+update publicly any forward-looking statement for any reason. 
+PART I 
+ITEM 1. BUSINESS 
+Overview 
+Iteris, Inc.,
+formerly known as Iteris Holdings, Inc., is a leading provider of outdoor
+machine vision systems and sensors that optimize the flow of traffic and
+enhance driver safety. Using proprietary software and Intelligent
+Transportation Systems (“ITS”) industry expertise, we provide video sensor systems,
+transportation management and traveler information systems and other
+engineering and consulting services to the ITS industry. The ITS industry is
+comprised of companies applying a variety of technologies to enable the safe
+and efficient movement of people and goods. We use our outdoor image
+recognition software expertise to develop proprietary algorithms for video
+sensor systems that improve vehicle safety and the flow of traffic. Using our
+knowledge of the ITS industry, we design and implement transportation
+management systems that help public agencies reduce traffic congestion and
+provide greater access to traveler information. 
+We
+were originally incorporated in Delaware in 1987 as Odetics, Inc. and in
+September 2003 changed our name to Iteris Holdings, Inc. to reflect
+our focus on the ITS industry and our capital structure at that time. On
+October 22, 2004, we completed a merger with our majority-owned
+subsidiary, Iteris, Inc. (the “Iteris Subsidiary”), and officially changed
+our corporate name from Iteris Holdings, Inc. to Iteris, Inc. 
+Our proprietary image recognition systems include Vantage and AutoVue.
+Vantage is a video vehicle detection system that detects the presence of
+vehicles on roadways. Vantage systems are used at signalized intersections to
+enable a more efficient allocation of green signal time and are also used for
+incident detection and highway traffic data collection applications. AutoVue
+Lane Departure Warning (“LDW”) systems consist of a small windshield mounted
+sensor that uses proprietary software to detect and warn drivers of unintended
+lane departures. To date, we and our strategic partner have sold approximately
+83,000 production AutoVue LDW systems for use on car and truck platforms in the
+North American and European markets. We believe that our AutoVue LDW technology
+is a broad sensor platform that, through additional software development, may
+be expanded to incorporate additional safety and convenience features. 
+Our transportation management systems business includes transportation
+engineering and consulting services focused on the planning, design,
+development and implementation of software-based systems that integrate
+sensors, video surveillance, computers and advanced communications equipment to
+enable public agencies to monitor, control and direct traffic flow, assist in
+the quick dispatch of emergency crews and distribute real-time information
+about traffic conditions. Our services include planning, design and
+implementation of surface transportation infrastructure systems. We perform analysis and study goods movement,
+commercial vehicle operations, travel demand forecasting and systems
+engineering, and identify mitigation measures to reduce traffic
+congestion. These services and systems
+are primarily sold to local, state and national transportation agencies in the
+United States. Our transportation
+management systems business is largely dependent upon governmental 
+3 
+funding and budgetary issues. The Federal Highway Bill that was passed in
+August 2005 provided for a significant increase in transportation funding over
+the following six years. We believe the
+recent expansion of our transportation management systems business was due in
+part to the passage of the Federal Highway Bill, combined with the expansion of
+transportation funds at state and local agencies throughout the country. 
+We currently
+operate in three reportable segments: Roadway Sensors, Automotive Sensors and
+Transportation Systems. The Roadway Sensors segment includes our Vantage
+vehicle detection systems for traffic intersection control, incident detection
+and certain highway traffic data collection applications. The Automotive Sensors segment is comprised
+of all activities related to our AutoVue LDW systems for vehicle safety. The
+Transportation Systems segment includes transportation engineering and
+consulting services and the development of transportation management and
+traveler information systems for the ITS industry. See Note 12 to the accompanying consolidated
+financial statements for further discussion of our operating segments. 
+Sales, Marketing and Principal Customers 
+We
+sell our Vantage vehicle detection systems through indirect sales channels
+comprised of independent dealers in the United States and Canada who sell
+integrated systems and related products to the traffic management market, as
+well as directly to the traffic management market using a combination of our
+own sales personnel and an outside sales organization. Our independent dealers
+are primarily responsible for sales, installation and support of Vantage
+systems. These dealers maintain an inventory of demonstration traffic products
+from various manufacturers including our Vantage vehicle detection systems and
+sell directly to government agencies and installation contractors. These
+dealers often have long-term arrangements with the government agencies in their
+territory for the supply of various products for the construction and
+renovation of traffic intersections. We hold technical training classes for
+dealers and end users and maintain a full-time staff of customer support
+technicians to provide technical assistance when needed. 
+Our marketing strategy for AutoVue is to establish it as the leading
+platform for in-vehicle video sensing for heavy trucks and passenger cars. We sell AutoVue LDW systems directly to heavy
+truck manufacturers and to U.S. truck fleets, and our AutoVue LDW system is
+currently offered as an option on certain heavy trucks, including
+Mercedes-Benz, MAN, Iveco, DAF, Scania, Freightliner, International and FUSO,
+as well as Neoplan and MAN luxury bus and coach lines. We market the licensing
+of our LDW technology to manufacturers of passenger automobiles through an
+exclusive strategic relationship with Valeo Schalter and Sensuren GmbH (“Valeo”),
+an independent automotive supplier. In connection with this marketing effort,
+we provide specific contract engineering services, technical marketing and
+sales support to Valeo, which to date has enabled the launch of our LDW
+technology on three Infiniti car platforms, the FX, M and Q, where our LDW
+system is offered as part of the technology option package. We plan to continue
+to provide technical marketing and sales support to Valeo in our efforts to win
+new original equipment manufacturer (“OEM”) customers for the passenger car
+market as well as contract engineering services related to the possible launch
+of new platforms that include our AutoVue LDW system. 
+We market and sell our transportation management systems and traveler
+information services directly to government agencies pursuant to negotiated
+contracts that involve competitive bidding and specific qualification
+requirements. Most of our contracts with federal, state and municipal customers
+provide for cancellation or renegotiation at the option of the customer upon
+reasonable notice and fees paid for modification. We use selected members of
+our engineering team divided on a regional basis to serve in sales and business
+development functions. We do not engage in sales of transportation management
+systems and traveler information services outside of the U.S. Sales of our
+transportation management systems contracts generally involve long lead times
+and require extensive specification development, evaluation and price
+negotiations. 
+Our largest
+customer accounted for 12.4% of total net sales and contract revenues in the
+fiscal year ended March 31, 2007 (“Fiscal 2007”). 
+Manufacturing and Materials 
+We use contract manufacturers to build subassemblies that are used in
+our Vantage products. Additionally, we procure certain components from
+qualified suppliers, both globally and locally, and use multi-sourcing
+strategies when technically and economically feasible to mitigate supply risk.
+These subassemblies and components are delivered to our Anaheim facility where
+they go through final assembly and testing prior to shipment to our customers.
+Our manufacturing activities are conducted in approximately 8,000 square feet
+of space at our Anaheim facility. Production volume at our subcontractors is
+based upon quarterly forecasts that we adjust on a monthly basis to control
+inventory. For sales of AutoVue LDW systems to the truck market, we subcontract
+the manufacture of our AutoVue LDW systems to two manufacturers, and our
+internal processes are limited primarily to testing and final verification. For
+AutoVue LDW sales to the passenger car market, we 
+4 
+anticipate that all manufacturing will be done by
+Valeo; however, we plan to continue to provide engineering support to Valeo. We
+currently do not manufacture any of the hardware used in the transportation
+management and traveler information systems that we design and implement. Our
+production facility is currently ISO 9001 certified. 
+Customer
+Support and Services 
+We provide
+warranty service and support for our Vantage and AutoVue products, as well as
+follow-up service and support for which we charge separately. Service revenue
+accounted for less than 1.0% of total net sales and contract revenues for
+Fiscal 2007. We believe customer support is a key competitive factor. 
+Backlog 
+Our backlog of unfulfilled firm orders was approximately $25.7 million
+as of March 31, 2007, which was comprised of $3.5 million related to
+Roadway Sensors, $2.1 million related to Automotive Sensors and $20.1 million
+related to Transportation Systems. Substantially all of the backlog for Roadway
+Sensors and Automotive Sensors is expected to be recognized as revenue in the
+fiscal year ending March 31, 2008 (“Fiscal 2008”), while approximately
+75.0% of Transportation Systems backlog is expected to be recognized as revenue
+in Fiscal 2008. At March 31, 2006, we had backlog of approximately $20.3
+million, which was comprised of $1.5 million related to Roadway Sensors, $3.0
+million related to Automotive Sensors and $15.8 million related to
+Transportation Systems. All backlog as of March 31, 2006 for Roadway Sensors
+and Automotive Sensors was recognized as revenue in Fiscal 2007 while 58.9% of
+March 31, 2006 backlog for Transportation Systems was recognized as revenue in
+Fiscal 2007. Pursuant to the customary terms of our agreements with government
+contractors and other customers, customers can generally cancel or
+reschedule orders with little or no penalties. Lead times for the release
+of purchase orders often depend upon the scheduling and forecasting practices
+of our individual customers, which also can affect the timing of the conversion
+of our backlog into revenues. For these reasons, among others, our backlog at a
+particular date may not be indicative of our future revenues. 
+Product Development 
+Most of our development activities are conducted at our principal
+facilities in Anaheim, California. Our company-sponsored research and
+development costs and expenses were approximately $4.0 million for Fiscal 2007,
+$5.2 million for the fiscal year ended March 31, 2006 (“Fiscal 2006”), and
+$6.2 million for the fiscal year ended March 31, 2005 (“Fiscal 2005”). We
+expect to continue to pursue significant product development programs and incur
+significant research and development expenditures. 
+Competition 
+We generally face significant competition in each of our target
+markets. Increased competition may result in price reductions, reduced gross
+margins and loss of market share, any of which could have a material adverse
+effect on our business, financial condition and results of operations. We
+believe that AutoVue is the only established commercially-available lane
+departure warning system used in the U.S. and in Europe in the heavy truck
+market. Potential competitors of AutoVue include Delphi Automotive Systems
+Corporation, NEC Corporation and Hitachi Ltd. in Japan and Robert Bosch GmbH in
+Europe, as well as Siemens, Continental Tavis, Visteon and Cognex, which could
+be currently developing video sensor technologies for the vehicle industry that
+could be used for lane departure warning systems. In the market for our Vantage
+vehicle detection systems, we compete with manufacturers of other above ground
+video camera detection systems such as Econolite Control Products, Inc.,
+Traficon, N.V., Quixote, and other non-intrusive detection devices including
+microwave, infrared, ultrasonic and magnetic detectors, as well as
+manufacturers and installers of in-pavement inductive loop products. 
+The transportation management and traveler information systems market
+is highly fragmented and is subject to evolving national and regional quality
+and safety standards. Our competitors vary in number, scope and breadth of the
+products and services they offer. Our competitors in advanced transportation
+management and traveler information systems include national corporations such
+as Transcore, Siemens, Telvent Farradyne, Kimley-Horn and Associates, Inc.
+and Delcan. Our competitors in transportation engineering, planning and design
+include major firms such as Parsons Brinkerhoff, Inc., URS, HNTB and
+Parsons Transportation Group, Inc., as well as many smaller regional
+engineering firms. 
+In general, the markets for the products and services we offer are
+highly competitive and are characterized by rapidly changing technology and
+evolving standards. Many of our current and prospective competitors have longer
+operating histories, greater name recognition, access to larger customer bases
+and significantly greater financial, technical, manufacturing, distribution and
+marketing resources than us. As a result, they may be able to adapt more
+quickly to new or emerging standards or technologies or to devote greater
+resources to the promotion and sale of their products. It is also possible that
+new competitors or alliances among competitors could emerge and rapidly acquire
+significant market share. We believe that our ability to compete effectively in
+our target markets will depend on a number of factors, including the success
+and timing of our new product development, the compatibility of our products
+with a broad range of computing systems, product quality and 
+5 
+performance, reliability, functionality, price, and
+service and technical support. Our failure to provide services and develop and
+market products that compete successfully with those of other suppliers and
+consultants in our target markets would have a material adverse effect on our
+business, financial condition and results of operations. 
+Intellectual Property and Proprietary
+Rights 
+Our ability to compete effectively depends in part on our ability to
+develop and maintain the proprietary aspects of our technology. Our policy is
+to obtain appropriate proprietary rights protection for any potentially
+significant new technology acquired or developed by us. We currently hold ten
+U.S. patents, which expire commencing in 2012, and have six U.S.
+patent applications pending relating to our outdoor image processing techniques
+used in our AutoVue systems. Nine of our patents relate specifically to our
+AutoVue technology and provide a basis for enhanced functionality for rain
+sensing and improved performance. We believe that our other patents, while
+important for our technology platforms, are less critical to our near term
+product strategy. We cannot assure you that any new patents will be granted
+pursuant to any outstanding or subsequent applications. 
+In addition to patent laws, we rely on copyright and trade secret laws
+to protect our proprietary rights. We attempt to protect our trade secrets and
+other proprietary information through agreements with customers and suppliers,
+proprietary information agreements with our employees and consultants, and
+other similar measures. We do not have any material licenses or trademarks
+other than those relating to product names. We cannot be certain that we will
+be successful in protecting our proprietary rights. While we believe our
+patents, patent applications, software and other proprietary know-how have
+value, changing technology makes our future success dependent principally upon
+our employees’ technical competence and creative skills for continuing innovation. 
+Litigation may be necessary in the future to enforce our proprietary
+rights, to determine the validity and scope of the proprietary rights of
+others, or to defend us against claims of infringement or invalidity by others.
+An adverse outcome in such litigation or similar proceedings could subject us
+to significant liabilities to third parties, require disputed rights to be
+licensed from others or require us to cease marketing or using certain
+products, any of which could have a material adverse effect on our business,
+financial condition and results of operations. In addition, the cost of
+addressing any intellectual property litigation claim, both in legal fees and
+expenses, as well as from the diversion of management’s resources, regardless
+of whether the claim is valid, could be significant and could have a material
+adverse effect on our business, financial condition and results of operations. 
+Employees 
+We refer to our employees as associates. As of June 5, 2007, we
+employed an aggregate of 237 associates, including 57 associates in general
+management, administration and finance; 31 associates in sales and marketing;
+113 associates in engineering and product development; 25 associates in
+operations, manufacturing and quality; and 11 associates in customer service.
+None of our associates are represented by a labor union, and we have never
+experienced a work stoppage. 
+Government Regulation 
+Our manufacturing operations are subject to various federal, state and
+local laws and regulations, including those restricting the discharge of
+materials into the environment. We are not involved in any pending or, to our
+knowledge, threatened governmental proceedings, which would require curtailment
+of our operations because of such laws and regulations. We continue to expend
+funds in connection with our compliance with applicable environmental
+regulations. These expenditures have not, however, been significant in the
+past, and we do not expect any significant expenditure in the near future.
+Currently, compliance with foreign laws has not had a material impact on our
+business and is not expected to have a material impact in the near future. 
+6 
+ITEM 1A. RISK FACTORS 
+Our
+business is subject to a number of risks, some of which are discussed below.
+Other risks are presented elsewhere in this report and in the information
+incorporated by reference into this report. You should consider the following
+risks carefully in addition to the other information contained in this report
+and our other filings with the SEC, including our subsequent reports on Forms
+10-Q and 8-K, before deciding to buy, sell or hold our common
+stock. The risks and uncertainties described below are not the only ones facing
+our company. Additional risks and uncertainties not presently known to us or
+that we currently deem immaterial may also affect our business operations. If
+any of these risks actually occurs, our business, financial condition or
+results of operations could be seriously harmed. In that event, the market
+price for our common stock could decline and you may lose all or part of your
+investment. 
+We May Need To Raise Additional Capital In
+The Future, Which May Not Be Available On Terms Acceptable To Us, Or At
+All. We have generated significant net losses and operating
+losses in recent periods, and have experienced volatility in our cash flows
+from operations ranging from positive cash flows from operations of $590,000 in
+the year ended March 31, 2005 to negative cash flows from operations of
+$2.0 million in the year ended March 31, 2007. Additionally, we failed to meet certain debt
+covenants under our prior credit agreement in two of our last seven fiscal
+quarters, but replaced that credit facility in October 2006 as further
+described in Note 5 to the accompanying consolidated financial statements. Furthermore, we have $9.9 million in
+subordinated convertible debentures that are due in full in May 2009. Should the holders of the convertible
+debentures not elect to convert the principal into shares of our common stock,
+we may need to raise additional capital to refinance this debt. 
+At March 31, 2007,
+we had $35,000 of cash and cash equivalents and relied on our line of credit to
+fund our operations. We may need to raise additional capital in the near future
+to fund our operations or to repay indebtedness. Such additional capital may be
+raised through bank borrowings, or other debt or equity financings. We cannot
+assure you that any additional capital will be available on a timely basis, on
+acceptable terms, or at all, and such additional financing may result in
+further dilution to our stockholders. 
+Our capital requirements will depend on many factors,
+including, but not limited to: 
+· market
+acceptance of our products and product enhancements, and the overall level of
+sales of our products; 
+· our
+ability to control costs; 
+· the
+supply of key components for our products; 
+· our
+ability to generate net income; 
+· increased
+research and development expenses; 
+· increased
+sales and marketing expenses; 
+· technological
+advancements and our competitors’ response to our products; 
+· capital
+improvements to new and existing facilities and enhancements to our
+infrastructure and systems; 
+· potential
+acquisitions of businesses and product lines; 
+· our
+relationships with customers and suppliers; 
+· government
+budgets, political agendas and other funding issues, including potential delays
+in government contract awards; 
+· our
+ability to successfully negotiate credit arrangements with our bank; and 
+7 
+· general
+economic conditions, including the effects of the current economic slowdown and
+international conflicts. 
+If our capital requirements are materially different
+from those currently planned, we may need additional capital sooner than
+anticipated. If additional funds are raised through the issuance of equity or
+convertible debt securities, the percentage ownership of our stockholders will
+be reduced and such securities may have rights, preferences and privileges
+senior to our common stock. Additional financing may not be available on
+favorable terms, on a timely basis, or at all. If adequate funds are not
+available or are not available on acceptable terms, we may be unable to
+continue our operations as planned, develop or enhance our products, expand our
+sales and marketing programs, take advantage of future opportunities or respond
+to competitive pressures. 
+We Have
+Historically Experienced Substantial Losses And May Continue To Experience
+Losses For The Foreseeable Future. Although we have achieved
+net income in recent periods, we experienced a net loss of $11.3 million in the
+year ended March 31, 2005. We
+cannot assure you that we will be able to sustain or improve our financial
+performance, or that we will be able to continue to achieve profitability on a
+quarterly or annual basis in the future. Most of our expenses are fixed in
+advance. As such, we generally are unable to reduce our expenses significantly
+in the short-term to compensate for any unexpected delay or decrease in
+anticipated revenues. As a result, we may continue to experience operating
+losses and net losses, which would make it difficult to fund our operations and
+achieve our business plan, and could cause the market price of our common stock
+to decline. 
+If Our
+Internal Controls Over Financial Reporting Do Not Comply With The Requirements
+Of The Sarbanes-Oxley Act, Our Business And Stock Price Could Be Adversely
+Affected. Along with our independent registered public
+accounting firm, we will be evaluating the effectiveness of our internal
+controls over financial reporting to comply with Section 404 of the
+Sarbanes-Oxley Act of 2002. Section 404 currently requires us to evaluate
+the effectiveness of our internal controls over financial reporting at the end
+of each fiscal year beginning in our fiscal year ending March 31, 2008 and
+to include a management report assessing the effectiveness of our internal
+controls over financial reporting in all annual reports beginning with our
+Annual Report on Form 10-K for the fiscal year ending March 31, 2008.
+Section 404 also requires our independent accountant to attest to, and report
+on, management’s assessment of our internal controls over financial reporting.
+We may not be able to complete our Section 404 compliance on a timely
+basis and even if we timely complete our compliance requirements, our
+independent auditors may still conclude that our internal controls over
+financial reporting are not effective. 
+Our management, including our CEO and CFO, does not
+expect that our internal controls over financial reporting will prevent all
+error and all fraud. A control system, no matter how well designed and
+operated, can provide only reasonable, not absolute, assurance that the control
+system’s objectives will be met. Further, the design of a control system must
+reflect the fact that there are resource constraints, and the benefits of controls
+must be considered relative to their costs. Because of the inherent limitations
+in all control systems, no evaluation of controls can provide absolute
+assurance that all control issues and instances of fraud, if any, within the
+company have been, or will be detected. These inherent limitations include the
+realities that judgments in decision-making can be faulty and that breakdowns
+can occur because of simple error or mistake. Controls can also be circumvented
+by the individual acts of some persons, by collusion of two or more people, or
+by management override of the controls. The design of any system of controls is
+based in part on certain assumptions about the likelihood of future events, and
+we cannot assure you that any design will succeed in achieving its stated goals
+under all potential future conditions. Over time, our controls may become
+inadequate because of changes in conditions or deterioration in the degree of
+compliance with policies or procedures. Because of the inherent limitations in
+a cost-effective control system, misstatements due to error or fraud may occur
+and not be detected. 
+As of March 31, 2005, we became aware of a
+material weakness in our internal controls related to the accounting for the
+consolidation of our deferred compensation savings plan and certain contract
+administration. We cannot assure you that we or our independent registered
+public accounting firm will not identify additional material weaknesses in our
+internal controls. A material weakness is a control deficiency, or combination
+of control deficiencies, that results in more than a remote likelihood that a
+material misstatement of the annual or interim financial statements will not be
+prevented or detected. Based on our evaluation, our management concluded that, as
+of March 31, 2004, our internal control over financial reporting was not
+effective due to the existence of one material weakness. We may experience
+additional material weaknesses in the future. If our internal controls over
+financial reporting are not considered adequate, we may experience a loss of
+public confidence, which could have an adverse effect on our business and our
+stock price. 
+8 
+We May Experience Production Gaps Which Could
+Materially And Adversely Impact Our Sales And Financial Results And The Ultimate
+Acceptance Of Our Products. It
+is possible that we could experience unforeseen quality control issues or part
+shortages as we increase production to meet current demand of our
+products. We have historically used
+single suppliers for certain of our components in our AutoVue and Vantage
+products. Should any such delay or disruption occur, our future sales will
+likely be materially and adversely affected. 
+Additionally, we rely heavily on select contract manufacturers to
+produce many of our products. Although
+we believe our contract manufacturers have sufficient capacity to meet our
+production schedules for the foreseeable future and we believe we could find
+alternative contract manufacturing sources if necessary, we could experience a
+production gap if for any reason our contract manufacturers were unable to meet
+our production requirements. 
+We Depend Upon Valeo To Market Our AutoVue
+Technologies For The OEM Passenger Car Market. We have
+granted Valeo the exclusive right to sell and manufacture our AutoVue LDW
+system to the worldwide passenger car market in exchange for royalty payments
+for each AutoVue unit sold. As such, the future success and broad market
+acceptance of our AutoVue technologies in the passenger car market will depend
+upon Valeo’s ability to manufacture, market and sell our technologies, and to
+convince more OEM passenger car manufacturers to adopt our technologies. If
+Valeo does not devote considerable resources and aggressively pursue
+opportunities, our expansion into the passenger car market could be adversely
+affected. 
+We May Be Unable To Attract And Retain Key
+Personnel, Which Could Seriously Harm Our Business. Due to
+the specialized nature of our business, we are highly dependent on the
+continued service of our executive officers and other key management,
+engineering and technical personnel. The loss of any of our executive officers
+or key members of management could adversely affect our business, financial
+condition or results of operations. Our success will also depend in large part
+upon our ability to continue to attract, retain and motivate qualified
+engineering and other highly skilled technical personnel. In particular, the
+future success of our Transportation Systems segment will depend on our ability
+to hire additional qualified engineers and planners. Competition for qualified
+employees, particularly development engineers, is intense. We may not be able
+to continue to attract and retain sufficient numbers of such highly skilled
+employees. Our inability to attract and retain additional key employees or the
+loss of one or more of our current key employees could adversely affect our
+business, financial condition and results of operations. 
+If We Are Unable To Develop And Introduce New
+Products And Product Enhancements Successfully And In A Cost-Effective And
+Timely Manner, Or Are Unable To Achieve Market Acceptance Of Our New Products,
+Our Operating Results Would Be Adversely Affected. We believe
+our revenue growth and future operating results will depend on our ability to
+complete development of new products and enhancements, introduce these products
+in a timely, cost-effective manner, achieve broad market acceptance of these
+products and enhancements, and reduce our product costs. We cannot guarantee
+the success of these products and we may not be able to introduce any new
+products or any enhancements to our existing products on a timely basis, or at
+all. In addition, the introduction of any new products could adversely affect
+the sales of certain of our existing products. 
+We believe that we must continue to make substantial
+investments to support ongoing research and development in order to remain
+competitive. We need to continue to develop and introduce new products that
+incorporate the latest technological advancements in outdoor image processing
+hardware, software and camera technologies in response to evolving customer
+requirements. We cannot assure you that
+we will be able to adequately manage product transition issues. Our business and results of operations could
+be adversely affected if we do not anticipate or respond adequately to
+technological developments or changing customer requirements or if we cannot
+adequately manage inventory issues typically related to new product transitions
+and introductions. We cannot assure you that any such investments in research
+and development will lead to any corresponding increase in revenue. 
+Market acceptance of our new products depends upon
+many factors, including our ability to accurately predict market requirements
+and evolving industry standards, our ability to resolve technical challenges in
+a timely and cost-effective manner, qualify any new products with OEMs and
+achieve manufacturing efficiencies, the perceived advantages of our new
+products over traditional products and the marketing capabilities of our
+independent distributors and strategic partners, including Valeo’s ability to
+expand sales of AutoVue in the passenger car market. The success of our AutoVue
+system will also depend in part on the success of the automotive vehicles that
+incorporate our technology, as well as the success of optional equipment that
+OEMs bundle with our technologies. 
+9 
+Certain of the components used in our Vantage and
+AutoVue products may need to be re-engineered in the next 12 to 18 months as
+the industry is moving towards a standard of using lead-free components. We
+cannot assure you as to the timing of the adoption of this new standard or our
+ability to successfully redesign our products to incorporate compliant
+components and gain market acceptance of such redesigned products. In addition,
+if the standard is adopted earlier than anticipated we may experience a
+shortage of Vantage and AutoVue products as a result of potential scarcity of
+lead-free components. 
+Our business and results of operations could also be
+seriously harmed by any significant delays in our new product development.
+Certain of our new products could contain undetected design faults and software
+errors or “bugs” when first released by us, despite our testing. We may not
+discover these faults or errors until after a product has been installed and
+used by our customers. Any faults or errors in our existing products or in any
+new products may cause delays in product introduction and shipments, require
+design modifications or harm customer relationships, any of which could
+adversely affect our business and competitive position. 
+The Markets In Which We Operate Are Highly
+Competitive And Have Many More Established Competitors, Which Could Adversely
+Affect Our Sales Or The Market Acceptance Of Our Products. We
+compete with numerous other companies in our target markets including, but not
+limited to, large, multinational corporations, which include tier one
+automotive suppliers, and many smaller regional engineering firms. We expect
+such competition to increase due to technological advancements, industry
+consolidations and reduced barriers to entry. Increased competition is likely
+to result in price reductions, reduced gross margins and loss of market share,
+any of which could seriously harm our business, financial condition and results
+of operations. We have experienced more competition in our Roadway Sensors
+segment in Fiscal 2007 as the Department of Transportation in one of our
+largest sales territories has recently moved to a multi-source contracting
+environment from one in which Iteris was the sole supplier. In addition, one of
+the other developers of LDW systems was recently acquired by a larger company.
+While this developer has not been a material competitor to date, we may
+experience more competition from this provider as a result of its greater
+access to resources from its acquirer, and additional competitors may enter
+this market in the future. 
+Many of our competitors have far greater name
+recognition and greater financial, technological, marketing and customer
+service resources than we do. This may allow them to respond more quickly to
+new or emerging technologies and changes in customer requirements. It may also
+allow them to devote greater resources to the development, promotion, sale and
+support of their products than we can. Recent consolidations of end users,
+distributors and manufacturers in our target markets have exacerbated this
+problem. As a result of the foregoing factors, we may not be able to compete
+effectively in our target markets and competitive pressures could adversely
+affect our business, financial condition and results of operations. 
+An Economic Slowdown Or The
+Significant Military Operations In The Middle East Or Elsewhere May Impact
+Government Funding Or Consumer Spending, Causing A Decline In Our Revenues. In the near term, the funding of U.S. military
+operations in the Middle East or elsewhere may cause disruptions in funding of
+government contracts. Since military
+operations of such magnitude are not routinely included in U.S. defense
+budgets, supplemental legislative funding actions are often required to finance
+such operations. Even when such legislation is enacted, it may not be adequate
+for ongoing operations, causing other government resources to be temporarily or
+permanently diverted. Since a
+significant portion of our sales are derived from contracts with government
+agencies, such diversion of funds could produce interruptions in funding or
+delays in receipt of our contracts, causing disruptions and adversely effecting
+our revenue and operations. 
+Concerns about the recent international conflicts and
+terrorist and military actions, as well as concerns about inflation, decreased
+consumer confidence, and reduced corporate profits and capital spending have
+also resulted in a downturn in worldwide economic conditions, particularly in
+the United States. These unfavorable economic conditions may have a negative
+impact on customer orders (and also may result in decreased sales of
+automobiles and trucks that incorporate our LDW systems). Such concerns may result in cancellations and
+rescheduling of backlog. In addition,
+the recent decline in the U.S. real estate market, particularly in new home
+construction, could adversely impact new road construction resulting in a
+decline in Roadway Sensor and Automotive Sensor net sales and Transportation
+Systems contract revenues. Any of the
+foregoing political, social and economic conditions make it extremely difficult
+for our customers, our suppliers and us to accurately forecast and plan future
+business activities and could result in a decline in our net sales and contract
+revenues. If such conditions continue or worsen, our business, financial
+condition and results of operations could be materially and adversely affected. 
+New Environmental Regulations May
+Result In A Decline In Our AutoVue Sales and Royalties. Recent environmental
+regulations were effected in Europe effective in 2006, which required more
+stringent emissions compliance in 
+10 
+new
+trucks manufactured in Europe after 2006. 
+These regulations caused the cost of certain trucks to increase
+significantly and could cause a decline in new truck sales in Europe in the
+near future. Similar regulations have
+been announced in North America that may impact diesel engines built after
+January 2007, which could similarly impact North American OEM truck sales in
+general. We may experience a decline in
+our LDW sales to truck OEMs related to these stricter regulations. 
+We Depend On Government Contracts And
+Subcontracts, And Because Many Of Our Government Contracts Are Fixed Price
+Contracts, Higher Than Anticipated Costs Will Reduce Our Profit And Could
+Adversely Impact Our Operating Results. A significant portion
+of our sales are derived from contracts with governmental agencies, either as a
+general contractor, subcontractor or supplier. Government contracts represented
+approximately 37.8%, 38.3% and 37.4% of our total net sales and contract
+revenues for the years ended March 31, 2007, 2006 and 2005, respectively.
+We anticipate that revenue from government contracts will continue to increase
+in the near future. Government business is, in general, subject to special
+risks and challenges, including: 
+· long
+purchase cycles or approval processes; 
+· competitive
+bidding and qualification requirements; 
+· the
+impact of international conflicts; 
+· performance
+bond requirements; 
+· changes
+in government policies and political agendas; 
+· delays
+in funding, including the delays in the allocation of funds to state and local
+agencies from the U.S. Federal Highway Bill; 
+· other
+government budgetary constraints and cut-backs; and 
+· milestone
+requirements and liquidated damage provisions for failure to meet contract
+milestones. 
+In addition, a large number of our government
+contracts are fixed price contracts. As a result, we may not be able to recover
+any cost overruns we may incur. These fixed price contracts require us to
+estimate the total project cost based on preliminary projections of the project’s
+requirements. The financial viability of any given project depends in large
+part on our ability to estimate these costs accurately and complete the project
+on a timely basis. In the event our costs on these projects exceed the fixed
+contractual amount, we will be required to bear the excess costs. Such additional
+costs would adversely affect our financial condition and results of operations.
+Moreover, certain of our government contracts are subject to termination or
+renegotiation at the convenience of the government, which could result in a
+large decline in our net sales and contract revenues in any given quarter. Our
+inability to address any of the foregoing concerns or the loss or renegotiation
+of any material government contract could seriously harm our business,
+financial condition and results of operations. 
+Our Quarterly Operating Results Fluctuate As A
+Result Of Many Factors. Therefore, We May Fail To Meet Or Exceed The
+Expectations Of Securities Analysts And Investors, Which Could Cause Our Stock
+Price To Decline. Our quarterly revenues and operating results
+have fluctuated and are likely to continue to vary from quarter to quarter due
+to a number of factors, many of which are not within our control. Factors that
+could affect our revenues include, among others, the following: 
+· changes
+in our pricing policies and the pricing policies of our suppliers and
+competitors, pricing concessions on volume sales, as well as increased price
+competition in general; 
+· the
+long lead times associated with government contracts or required by vehicle
+manufacturers; 
+· delays
+in government contracts from time to time, including from delays in the
+allocation of funds to state and local agencies from the U.S. Federal Highway
+Bill; 
+· our
+ability to raise additional capital; 
+11 
+· our
+ability to control costs; 
+· the
+mix of our products and services sold in a quarter, which mix has varied and is
+expected to continue to vary from time to time; 
+· seasonality
+due to winter weather conditions; 
+· international
+conflicts and acts of terrorism; 
+· declines
+in new home construction and related road construction; 
+· our
+ability to develop, introduce, patent, market and gain market acceptance of new
+products, applications and product enhancements in a timely manner, or at all; 
+· market
+acceptance of the products incorporating our technologies and products; 
+· the
+size, timing, rescheduling or cancellation of significant customer orders; 
+· the
+introduction of new products by competitors; 
+· the
+availability and cost of components used in the manufacture of our products; 
+· our
+success in expanding and implementing our sales and marketing programs; 
+· the
+effects of technological changes in our target markets; 
+· the
+amount of our backlog at any given time; 
+· the
+nature of our government contracts; 
+· deferrals
+of customer orders in anticipation of new products, applications or product
+enhancements; 
+· risks
+and uncertainties associated with our international business; 
+· currency
+fluctuations and our ability to get currency out of certain foreign countries;
+and 
+· general
+economic and political conditions. 
+Due to all of the factors listed above as well as
+other unforeseen factors, our future operating results could be below the
+expectations of securities analysts or investors. If that happens, the trading
+price of our common stock could decline. As a result of these quarterly
+variations, you should not rely on quarter-to-quarter comparisons of our
+operating results as an indication of our future performance. 
+We May Engage In Acquisitions Of Companies Or
+Technologies That May Require Us To Undertake Significant Capital
+Infusions And Could Result In Disruptions Of Our Business And Diversion Of
+Resources And Management Attention. We have historically
+acquired, and may in the future acquire, complementary businesses, products and
+technologies. Acquisitions may require significant capital infusions and, in
+general, acquisitions also involve a number of special risks, including: 
+· potential
+disruption of our ongoing business and the diversion of our resources and
+management’s attention; 
+· the
+failure to retain or integrate key acquired personnel; 
+12 
+· the
+challenge of assimilating diverse business cultures, and the difficulties in
+integrating the operations, technologies and information system of the acquired
+companies; 
+· increased
+costs to improve managerial, operational, financial and administrative systems
+and to eliminate duplicative services; 
+· the
+incurrence of unforeseen obligations or liabilities; 
+· potential
+impairment of relationships with employees or customers as a result of changes
+in management; and 
+· increased
+interest expense and amortization of acquired intangible assets. 
+Our competitors are also soliciting potential
+acquisition candidates, which could both increase the price of any acquisition
+targets and decrease the number of attractive companies available for
+acquisition. Acquisitions may also materially and adversely affect our
+operating results due to large write-offs, contingent liabilities, substantial
+depreciation, deferred compensation charges or intangible asset amortization,
+or other adverse tax or accounting consequences. We cannot assure you that we
+will be able to identify or consummate any additional acquisitions,
+successfully integrate any acquisitions or realize the benefits anticipated
+from any acquisition. 
+We Have
+Experienced Growth In Recent Periods. If We Fail To Manage Our Growth
+Effectively, We May Be Unable To Execute Our Business Plan And
+May Experience Future Weaknesses In Our Internal Controls. We
+have expanded our overall business. In order to achieve our business
+objectives, we will need to continue to expand our business and add additional
+qualified personnel. Such expansion has placed and is expected to continue to
+place, a significant strain on our managerial, administrative, operational,
+financial and other resources. If we are unable to successfully manage our
+growth, our business, financial condition and results of operations will be
+adversely affected. 
+To accommodate this growth, we launched a new ERP
+system in April 2006. Accordingly, we may experience problems commonly
+experienced by other companies in connection with such implementations,
+including but not limited to, potential bugs in the system, component or supply
+delays, training requirements and other integration challenges and delays. Any
+difficulties we might experience in connection with our new ERP system could
+have a material adverse effect on our financial reporting system and internal
+controls. 
+If We Do Not Keep Pace With Rapid Technological
+Changes And Evolving Industry Standards, We Will Not Be Able To Remain Competitive
+And There Will Be No Demand For Our Products. Our markets are
+in general characterized by the following factors: 
+· rapid
+technological advances; 
+· downward
+price pressure in the marketplace as technologies mature; 
+· changes
+in customer requirements; 
+· frequent
+new product introductions and enhancements; and 
+· evolving
+industry standards and changes in the regulatory environment. 
+Our future success will depend upon our ability to
+anticipate and adapt to changes in technology and industry standards, and to
+effectively develop, introduce, market and gain broad acceptance of new
+products and product enhancements incorporating the latest technological
+advancements. In particular, our LDW system is incorporated into automobiles
+and trucks that face significant technological changes in each model year and
+among different vehicle models. Accordingly, we must adapt our technology from
+time to time to function with such changes. 
+We May Not Be Able To Adequately Protect Or
+Enforce Our Intellectual Property Rights, Which Could Harm Our Competitive
+Position. If we are not able to adequately protect or enforce
+the proprietary aspects of our technology, competitors could be able to access
+our proprietary technology and our business, financial condition and results of
+operations 
+13 
+will
+likely be seriously harmed. We currently attempt to protect our technology
+through a combination of patent, copyright, trademark and trade secret laws,
+employee and third party nondisclosure agreements and similar means. Despite
+our efforts, other parties may attempt to disclose, obtain or use our
+technologies or systems. Our competitors may also be able to independently
+develop products that are substantially equivalent or superior to our products
+or design around our patents. In addition, the laws of some foreign countries
+do not protect our proprietary rights as fully as do the laws of the United
+States. As a result, we may not be able to protect our proprietary rights
+adequately in the United States or abroad. 
+Litigation may be
+necessary in the future to enforce our intellectual property rights or to
+determine the validity and scope of the proprietary rights of others.
+Litigation may also be necessary to defend against claims of infringement or
+invalidity by others. An adverse outcome in litigation or any similar
+proceedings could subject us to significant liabilities to third parties,
+require us to license disputed rights from others or require us to cease
+marketing or using certain products or technologies. We may not be able to obtain
+any licenses on terms acceptable to us, or at all. We also may have to
+indemnify certain customers or strategic partners if it is determined that we
+have infringed upon or misappropriated another party’s intellectual property.
+Any of these results could adversely affect our business, financial condition
+and results of operations. In addition, the cost of addressing any intellectual
+property litigation claim, including legal fees and expenses, and the diversion
+of management’s attention and resources, regardless of whether the claim is
+valid, could be significant and could seriously harm our business, financial
+condition and results of operations. 
+The Trading Price Of Our Common Stock Is Highly
+Volatile. The trading price of our common stock has been
+subject to wide fluctuations in the past. Since January 2000, our
+Class A common stock (now known as our common stock) has traded at prices
+as low as $0.45 per share and as high as $29.44 per share. The market price of
+our common stock could continue to fluctuate in the future in response to
+various factors, including, but not limited to: 
+· quarterly
+variations in operating results; 
+· our
+ability to control costs, improve cash flow and sustain profitability; 
+· our
+ability to raise additional capital; 
+· shortages
+announced by suppliers; 
+· announcements
+of technological innovations or new products or applications by our
+competitors, customers or us; 
+· transitions
+to new products or product enhancements; 
+· acquisitions
+of businesses, products or technologies; 
+· the
+impact of any litigation; 
+· changes
+in investor perceptions; 
+· government
+funding, political agendas and other budgetary issues; 
+· changes
+in earnings estimates or investment recommendations by securities analysts; and 
+· international
+conflicts, political unrest and acts of terrorism. 
+In addition, as of March 31, 2007, options to purchase
+an aggregate of 711,000 shares of our common stock at a weighted average price
+of $0.53 per share terminate on or prior to September 30, 2007. Our common stock has traditionally been
+thinly traded. The exercise of these options and the sale of a large number of
+shares of our common stock could cause our stock price to decline. 
+The stock market in general has recently experienced
+volatility, which has particularly affected the market prices of equity
+securities of many technology companies. This volatility has often been
+unrelated to the operating performance of these 
+14 
+companies.
+These broad market fluctuations may adversely affect the market price of our
+common stock. In the past, companies that have experienced volatility in the
+market price of their securities have been the subject of securities class
+action litigation. If we were to become the subject of a class action lawsuit,
+it could result in substantial losses and divert management’s attention and
+resources from other matters. 
+Our International Business Operations May Be
+Threatened By Many Factors That Are Outside Of Our Control. We
+currently market our AutoVue and Vantage products internationally and we
+anticipate that our international operations will expand in the near future.
+International business operations are subject to various inherent risks
+including, among others: 
+· currency
+fluctuations and restrictions; 
+· political,
+social and economic instability; 
+· longer
+accounts receivable payment cycles; 
+· import
+and export license requirements and restrictions of the United States and each
+other country in which we operate; 
+· unexpected
+changes in regulatory requirements, tariffs and other trade barriers or
+restrictions; 
+· the
+burdens of compliance with a wide variety of foreign laws and more restrictive
+labor laws and obligations; 
+· difficulties
+in managing and staffing international operations; 
+· potentially
+adverse tax consequences; and 
+· reduced
+protection for intellectual property rights in some countries. 
+All of our international sales are denominated in U.S.
+dollars. As a result, an increase in the relative value of the dollar could
+make our products more expensive and potentially less price competitive in
+international markets. We do not engage in any transactions as a hedge against
+risks of loss due to foreign currency fluctuations. 
+Any of the factors mentioned above may adversely
+affect our future international sales and, consequently, affect our business,
+financial condition and operating results. Furthermore, as we increase our
+international sales, our total revenues may also be affected to a greater
+extent by seasonal fluctuations resulting from lower sales that typically occur
+during the summer months in Europe and other parts of the world. 
+We Could Experience Negative Financial Impacts
+Arising From Developments In Contingencies Created Under Our Previous Structure
+Or By Former Subsidiaries. Although we divested ourselves of
+all business units, with the exception of our Iteris business, from time to
+time we could experience unforeseen developments in contingencies related to
+our former subsidiaries. For example, in July 2006 we entered into a settlement
+agreement in connection with a lawsuit brought against Mariner
+Networks, Inc., one of our former subsidiaries, by one of Mariner’s
+suppliers, pursuant to which we issued 88,912 shares of our common stock to
+this supplier (valued at $213,000 as of the date of issuance), paid this
+supplier $125,000 on October 20, 2006 and are required to pay an additional
+$350,000 in 36 equal monthly installments of $9,700 beginning in November
+2006. Although we are not aware of any
+other material contingencies, it is possible that other matters could be
+brought against us in connection with activities related to former subsidiaries
+and that such matters could materially and adversely affect our financial
+results and cash flows. 
+Some Of Our Directors, Officers And Their
+Affiliates Can Control The Outcome Of Matters That Require The Approval Of Our
+Stockholders, And Accordingly We Will Not Be Able To Engage In Certain
+Transactions Without Their Approval. As of March 31, 2007,
+our officers and directors beneficially owned approximately 12% of the
+outstanding shares of our common stock (and approximately 18% of our common
+stock when including options, warrants and other convertible securities held by
+them which are currently exercisable or convertible or will become exercisable
+or convertible within 60 days 
+15 
+after
+March 31, 2007). As a result of their stock ownership, our management will be
+able to significantly influence the election of our directors and the outcome
+of corporate actions requiring stockholder approval, such as mergers and
+acquisitions, regardless of how our other stockholders may vote. This
+concentration of voting control may have a significant effect in delaying,
+deferring or preventing a change in our management or change in control and may
+adversely affect the voting or other rights of other holders of common stock. 
+Certain Anti-Takeover Provisions May Affect
+The Price Of Our Common Stock And Discourage A Third Party From Acquiring Us. Certain
+provisions of our certificate of incorporation and our stockholder rights plan
+could make it difficult for a third party to acquire us, even though an
+acquisition might be beneficial to our stockholders. Such provisions could
+limit the price that investors might be willing to pay in the future for shares
+of our common stock. Under the terms of our certificate of incorporation, our
+Board of Directors is authorized to issue, without stockholder approval, up to
+2,000,000 shares of preferred stock with voting, conversion and other rights
+and preferences superior to those of our common stock. Our future issuance of
+preferred stock could be used to discourage an unsolicited acquisition
+proposal. In addition, in March 1998, we adopted a stockholder rights plan
+and declared a dividend of preferred stock purchase rights to our stockholders.
+We amended this plan in May 2004. In the event a third party acquires more
+than 15% of the outstanding voting control of our company or 15% of our
+outstanding common stock, the holders of these rights will be able to purchase
+the junior participating preferred stock at a substantial discount off of the
+then current market price. The exercise of these rights and purchase of a
+significant amount of stock at below market prices could cause substantial
+dilution to a particular acquirer and discourage the acquirer from pursuing our
+company. The mere existence of a stockholder rights plan often delays or makes
+a merger, tender offer or proxy contest more difficult. 
+ITEM 1B. UNRESOLVED STAFF COMMENTS 
+Not applicable. 
+ITEM 2. PROPERTIES 
+Our headquarters and principal operations are housed in approximately
+94,000 square feet of leased space located at 1515 South Manchester Boulevard
+in Anaheim, California, for which we pay a monthly lease rate of $92,000,
+exclusive of common area maintenance and certain utility costs. The Anaheim
+facility includes our operations and administrative offices (approximately
+84,000 dedicated square feet) and the operations of our former subsidiary,
+MAXxess Systems, Inc. (approximately 10,000 dedicated square feet). The
+lease for the Anaheim facility is expected to terminate in September 2007. 
+On May 25, 2007, we entered into an agreement to lease approximately
+50,000 square feet of space located in Santa Ana, California for a term of 88
+months, beginning in September 2007. This
+location will be the new location of our headquarters and principal operations.
+The monthly lease rate will be $102,000, inclusive of common area maintenance
+costs and certain utility costs, during the first year of the lease, and will
+increase each year thereafter, up to a maximum of $120,000 during the last year
+of the lease. The lease may be extended
+for a period of five years, at our option, at a lease rate to be based on the
+market lease rate for comparable property determined as of the commencement of
+the extension period. Subject to certain
+limitations, we also have a right of first offer with respect to additional
+space at the same location. 
+For additional information regarding our obligations under property
+leases, see Note 7 of Notes to Consolidated Financial Statements, included in
+Part IV, Item 15 of this report. 
+ITEM 3. LEGAL PROCEEDINGS 
+The information set forth under Note 7 of Notes to Consolidated
+Financial Statements, included in Part IV, Item 15 of this report, is
+incorporated herein by reference. 
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
+HOLDERS 
+No matters were submitted to a vote of our security holders during the
+three months ended March 31, 2007. 
+16 
+PART II 
+ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED
+STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+Our common stock is traded on the American Stock Exchange (“AMEX”)
+under the symbol “ITI”. The following
+table sets forth, for the periods indicated, the high and low sales prices for
+our common stock as reported by AMEX: 
+Common Stock 
+High 
+Low 
+Fiscal 2007 
+Quarter Ended June 30, 2006 
+$ 
+2.69 
+$ 
+2.10 
+Quarter Ended September 30, 2006 
+2.69 
+2.26 
+Quarter Ended December 31, 2006 
+2.69 
+1.38 
+Quarter Ended March 31, 2007 
+2.76 
+2.15 
+Fiscal 2006 
+Quarter Ended June 30, 2005 
+$ 
+2.89 
+$ 
+2.00 
+Quarter Ended September 30, 2005 
+3.40 
+2.57 
+Quarter Ended December 31, 2005 
+2.80 
+2.02 
+Quarter Ended March 31, 2006 
+2.80 
+1.85 
+On
+June 18, 2007, the last reported sales price of our common stock on the
+AMEX was $2.53. As of June 18,
+2007, we had 526 holders of record of our common stock according to information
+furnished by our transfer agent. 
+Dividend Policy 
+We have never paid or declared cash dividends on our common stock, and
+have no current plans to pay such dividends in the foreseeable future. We
+currently intend to retain any earnings for working capital and general
+corporate purposes. The payment of any future dividends will be at the
+discretion of our Board of Directors and will depend upon a number of factors,
+including, but not limited to, future earnings, the success of our business, our
+capital requirements, our general financial condition and future prospects,
+general business conditions, the consent of our lender and such other factors
+as the Board of Directors may deem relevant. 
+Recent Sales of Unregistered Securities 
+The following is a summary of our transactions during the year ended
+March 31, 2007, involving sales of our securities that were not registered
+under the Securities Act of 1933, as amended (the “Securities Act”): 
+(1) In August
+2006, we issued to Delta Networks, Inc. 88,912 shares of our common stock
+valued at $213,000 in connection with the settlement of a lawsuit by Delta
+against one of our former subsidiaries, Mariner Networks, Inc. 
+(2) In
+September 2006, we issued to Special Situations Fund III QP, L.P., Special
+Situations Fund III, L.P., Special Situations Cayman Fund, L.P. and Special
+Situations Private Equity Fund, L.P. (collectively, the “Funds”) warrants to
+purchase an aggregate of 246,250 shares of our commons stock, subject to
+adjustment in specified circumstances, in connection with the early exercise by
+the Funds of existing warrants to purchase an aggregate of 1,250,000 shares of
+common stock at an exercise price of $1.61 per share. We received $2.0 million from the Funds as
+payment in full of the aggregate exercise price of such existing warrants. The new warrants are immediately exercisable,
+have an exercise price of $3.25 per share, subject to adjustment in specified
+circumstances, and expire in September 2011. 
+We may redeem all of the warrants, at a price of $0.01 per share of
+common stock then purchaseable pursuant to the warrants if the closing bid
+price of one share of common stock equals or exceeds $6.50 for 20 consecutive
+trading days, subject to the rights of the holders thereof to exercise the
+warrants prior to the redemption date. 
+In order to exercise this redemption option, we must redeem all of the
+warrants on the same terms. 
+17 
+The issuance of securities in the transactions described in paragraphs
+1 and 2 above were effected without registration under the Securities Act in
+reliance on Section 4(2) thereof and Rule 506 of Registration D thereunder
+based on the status of each investor as an accredited investor defined under
+the Securities Act. None of the foregoing
+transactions was effected using any form of general advertising or general
+solicitation as such terms are used in Regulation D under the Securities Act. 
+Stock
+Performance Graph 
+The graph below shows the cumulative total return on
+investment assuming an investment of $100 on March 31, 2002 in our common
+stock, the NASDAQ Stock Market Index and the same peer group used by us last
+year, which is made up of the remaining members of the index used by us in
+prior years, the Media General Industry Group 836 for Diversified Electronics,
+which is no longer a published index. 
+Our common stock is currently listed on the AMEX under the symbol “ITI”
+and began trading on such exchange on December 9, 2004. Our common stock (formerly the Class A common
+stock) was listed on the NASDAQ National Market (now called the NASDAQ Global
+Market) until April 2002 and on the NASDAQ SmallCap Market (now called the
+NASDAQ Capital Market) from April 2002 to August 2003 and quoted on the OTC
+Bulletin Board from August 2003 to December 2004. The total stockholder return assumes
+reinvestment of dividends on a daily basis, although cash dividends have not
+been declared on our common stock. The
+stockholder returns shown in the following graph are not necessarily indicative
+of future performance. 
+Measurement Period 
+2002 
+2003 
+2004 
+2005 
+2006 
+2007 
+Iteris Common Stock 
+100.00 
+42.58 
+258.06 
+157.42 
+170.32 
+148.39 
+NASDAQ Market Index 
+100.00 
+72.11 
+109.76 
+111.26 
+132.74 
+139.65 
+Peer Group 
+100.00 
+62.01 
+111.93 
+85.59 
+112.90 
+114.99 
+18 
+Notwithstanding anything
+to the contrary set forth in any of our previous or future filings under the
+Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as
+amended, that might incorporate this report or future filings made by us under
+those statutes, the stock performance graph is not deemed filed with the
+Securities and Exchange Commission and shall not be deemed incorporated by
+reference into any prior filings or into any future filings made by us under
+those statutes. 
+ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA 
+The following table sets forth selected consolidated financial data for
+each of the five fiscal years ended March 31, 2007. The statement of
+operations and balance sheet data for the years ended and as of March 31,
+2007, 2006, 2005, 2004, and 2003 are derived from our audited consolidated
+financial statements. The accompanying consolidated financial statements have
+been restated to reflect the classification and presentation of our former
+subsidiaries, Broadcast, Inc., Zyfer Inc., and MAXxess Systems, Inc.,
+as discontinued operations for all periods presented. The following information should be read in
+conjunction with “Management’s Discussion and Analysis of Financial Condition
+and Results of Operations” and with our consolidated financial statements and
+the related notes thereto included elsewhere in this report. 
+19 
+Fiscal Year Ended March 31, 
+2007 
+2006 
+2005 
+2004 
+2003 
+(in thousands, except per share data) 
+Consolidated Statement of
+Operations Data: 
+Net sales and contract revenues: 
+Net
+sales 
+$ 
+36,248 
+$ 
+31,156 
+$ 
+29,062 
+$ 
+23,470 
+$ 
+19,112 
+Contract
+revenues 
+22,049 
+19,330 
+17,335 
+21,813 
+22,283 
+Total
+net sales and contract revenues 
+58,297 
+50,486 
+46,397 
+45,283 
+41,395 
+Costs of net sales and contract revenues: 
+Cost
+of net sales (a) 
+19,829 
+16,493 
+15,925 
+12,758 
+9,366 
+Cost
+of contract revenues (a) 
+14,460 
+12,600 
+13,789 
+14,712 
+15,110 
+Gross
+profit 
+24,008 
+21,393 
+16,683 
+17,813 
+16,919 
+Operating expenses: 
+Selling,
+general and administrative (a) 
+16,094 
+15,362 
+21,027 
+12,844 
+14,105 
+Research
+and development (a) 
+4,030 
+5,217 
+6,236 
+3,923 
+3,908 
+Amortization
+of intangible assets 
+147 
+147 
+114 
+— 
+— 
+Deferred
+compensation expense (benefit) 
+(91 
+) 
+48 
+(484 
+) 
+868 
+— 
+Disposal
+of fixed assets 
+— 
+— 
+422 
+— 
+— 
+Acquired
+in-process research and development 
+— 
+— 
+140 
+— 
+— 
+Total
+operating expenses 
+20,180 
+20,774 
+27,455 
+17,635 
+18,013 
+Operating income (loss) 
+3,828 
+619 
+(10,772 
+) 
+178 
+(1,094 
+) 
+Non-operating income (expense): 
+Other
+income (expense), net 
+(653 
+) 
+35 
+1,054 
+1,003 
+417 
+Interest
+expense, net 
+(1,600 
+) 
+(1,459 
+) 
+(1,178 
+) 
+(123 
+) 
+(761 
+) 
+Income (loss) from continuing operations before
+income taxes and minority interest 
+1,575 
+(805 
+) 
+(10,896 
+) 
+1,058 
+(1,438 
+) 
+Income tax benefit (provision) 
+1,343 
+885 
+94 
+(100 
+) 
+— 
+Minority interest in earnings of subsidiary 
+— 
+— 
+(526 
+) 
+(2,813 
+) 
+(3,818 
+) 
+Income (loss) from continuing operations 
+2,918 
+80 
+(11,328 
+) 
+(1,855 
+) 
+(5,256 
+) 
+Income (loss) from discontinued operations, net
+of taxes 
+— 
+— 
+— 
+1,215 
+(7,892 
+) 
+Net income (loss) 
+$ 
+2,918 
+$ 
+80 
+$ 
+(11,328 
+) 
+$ 
+(640 
+) 
+$ 
+(13,148 
+) 
+Basic earnings (loss) per share: 
+Continuing
+operations 
+$ 
+0.10 
+$ 
+0.00 
+$ 
+(0.45 
+) 
+$ 
+(0.09 
+) 
+$ 
+(0.37 
+) 
+Discontinued
+operations 
+— 
+— 
+— 
+0.06 
+(0.55 
+) 
+Basic
+earnings (loss) per share 
+$ 
+0.10 
+$ 
+0.00 
+$ 
+(0.45 
+) 
+$ 
+(0.03 
+) 
+$ 
+(0.92 
+) 
+Diluted earnings (loss) per share: 
+Continuing
+operations 
+$ 
+0.09 
+$ 
+0.00 
+$ 
+(0.45 
+) 
+$ 
+(0.09 
+) 
+$ 
+(0.37 
+) 
+Discontinued
+operations 
+— 
+— 
+— 
+0.06 
+(0.55 
+) 
+Diluted
+earnings (loss) per share 
+$ 
+0.09 
+$ 
+0.00 
+$ 
+(0.45 
+) 
+$ 
+(0.03 
+) 
+$ 
+(0.92 
+) 
+Shares used in calculating basic earnings
+(loss) per share 
+29,698 
+28,182 
+25,284 
+19,454 
+14,276 
+Shares used in calculating diluted earnings
+(loss) per share 
+33,348 
+32,737 
+25,284 
+19,454 
+14,276 
+(a) Includes stock-based compensation expense
+as follows: 
+Cost of net sales 
+$ 
+13 
+$ 
+27 
+$ 
+280 
+$ 
+— 
+$ 
+— 
+Cost of contract revenues 
+60 
+205 
+2,391 
+— 
+— 
+Selling, general and administrative expense 
+195 
+364 
+7,063 
+— 
+— 
+Research and development expense 
+20 
+129 
+2,043 
+— 
+— 
+Total stock-based compensation expense 
+$ 
+288 
+$ 
+725 
+$ 
+11,777 
+$ 
+— 
+$ 
+— 
+20 
+At March 31, 
+2007 
+2006 
+2005 
+2004 
+2003 
+(in thousands) 
+Consolidated Balance Sheet
+Data: 
+Working capital 
+$ 
+6,979 
+$ 
+3,009 
+$ 
+2,197 
+$ 
+9,369 
+$ 
+3,368 
+Total assets 
+55,250 
+49,633 
+46,656 
+30,065 
+34,842 
+Long-term debt (less current portion) 
+9,760 
+11,374 
+10,315 
+891 
+1,265 
+Accumulated deficit 
+(107,438 
+) 
+(110,356 
+) 
+(110,436 
+) 
+(99,108 
+) 
+(98,468 
+) 
+Total stockholders’ equity (deficit) 
+25,687 
+18,635 
+17,462 
+(1,076 
+) 
+(5,340 
+) 
+21 
+ITEM 7. MANAGEMENT’S DISCUSSION
+AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+You should read the following
+discussion and analysis in conjunction with our Consolidated Financial
+Statements and related Notes thereto included in Part IV, Item 15 of this
+report and the “Risk Factors” section in Item 1A, as well as other
+cautionary statements and risks described elsewhere in this report, before
+deciding to purchase, hold or sell our common stock. 
+Overview 
+We are a leading provider of outdoor machine vision systems and sensors
+that optimize the flow of traffic and enhance driver safety. Using our
+proprietary software and ITS industry expertise, we provide video sensor
+systems, transportation management and traveler information systems and other
+engineering and consulting services to the ITS industry. We use our outdoor
+image recognition software expertise to develop proprietary algorithms for
+video sensor systems that improve vehicle safety and the flow of traffic. Using
+our knowledge of the ITS industry, we design and implement transportation
+management systems that help public agencies reduce traffic congestion and
+provide greater access to traveler information. 
+Our Vantage product is a video vehicle sensing system that detects the
+presence of vehicles on roadways. Vantage systems are used at signalized
+intersections to enable a more efficient allocation of green signal time and
+are also used for incident detection and highway traffic data collection
+applications. We sell and distribute our Vantage products primarily to
+commercial customers and municipal agencies. 
+Our AutoVue LDW systems consist of a small windshield mounted sensor
+that uses proprietary software to detect and warn drivers of unintended lane
+departures. Approximately 83,000 production AutoVue LDW units have been sold
+for truck and car platforms in the North American, European markets and Asian
+markets. Our AutoVue LDW systems are currently offered as an option on certain
+Mercedes-Benz, MAN, Iveco, DAF, Scania, International and Freightliner trucks.
+In Japan, our LDW system is a standard feature on certain FUSO heavy truck
+models. We provide an aftermarket kit to service the growing number of heavy
+truck fleet customers in North America. Using our aftermarket kit, our LDW
+systems can be installed on a variety of heavy trucks such as Freightliner,
+Volvo, Kennworth, Peterbilt, International and Mack. In September 2003, we
+entered into an agreement with Valeo, pursuant to which we granted Valeo the
+exclusive right to sell and manufacture our AutoVue LDW systems to the
+worldwide passenger car market in exchange for royalty payments for each
+AutoVue LDW unit sold. To date, royalty payments from Valeo have totaled approximately
+$484,000. Pursuant to this agreement, we also generate revenues from Valeo by
+providing specific contract engineering services, technical marketing and sales
+support to Valeo related to passenger car development activites and to enable
+the launch of our LDW on certain Infiniti vehicles. Valeo is currently in
+discussions to provide our LDW system to other passenger car OEMs; however, we
+cannot assure you that such discussions will be successful. We plan to continue
+to provide technical marketing and sales support to Valeo in our efforts to win
+new OEM customers for the passenger car market, as well as contract engineering
+services related to the possible launch of new Infiniti platforms that include
+our LDW system. We believe that AutoVue is a broad sensor platform that,
+through additional software development, may be expanded to incorporate
+additional safety and convenience features. 
+Our transportation
+management systems business includes transportation engineering and consulting
+services focused on the planning, design, development and implementation of
+software-based systems that integrate sensors, video surveillance, computers
+and advanced communications equipment to enable public agencies to monitor,
+control and direct traffic flow, assist in the quick dispatch of emergency
+crews and distribute real-time information about traffic conditions. Our
+services include planning, design and implementation of surface transportation
+infrastructure systems. We perform analysis
+and study goods movement, commercial vehicle operations, travel demand
+forecasting and systems engineering and identify mitigation measures to reduce
+traffic congestion. These services and
+systems are primarily sold to local, state and national transportation agencies
+in the United States. Our transportation management systems business is largely
+dependent upon governmental funding and budgetary issues. The Federal Highway
+Bill that was passed in August 2005 provided for a significant increase in
+transportation funding over the following six years. The recent growth in our
+transportation management systems business and our Vantage product business has
+been enabled in part by this bill, as well as by state transportation bonds
+such as the $20 billion infrastructure bond passed in California in November
+2006. Historically, there have been significant delays between the passage of
+funding bills and the allocation of related funding to specific contracts.
+Accordingly, while we have seen an increase in activity following the passage
+of the Federal Highway Bill, we cannot currently predict the full impact that
+this bill or state bonds will have on our transportation management systems
+business. We anticipate that the success of our transportation systems business
+will continue to be dependent in part on government spending and the budgetary
+process. 
+22 
+We have historically operated multiple business units. During the
+fiscal year ended March 31, 2003 (“Fiscal 2003”), we operated in three
+segments consisting of ITS, video products, and telecom products. The ITS
+segment consisted of our current operations, which was previously conducted by
+the Iteris Subsidiary. The video products segment consisted of our former
+wholly-owned subsidiaries, MAXxess Systems, Inc. (“MAXxess,” previously
+known as Gyyr Incorporated), which designed and manufactured security
+management systems, and Broadcast, Inc. (“Broadcast”), which developed and
+supplied software based systems to automate and control the multiple classes of
+equipment used in broadcast studios and satellite uplink facilities. Our
+telecom segment consisted of our wholly-owned subsidiary, Zyfer, Inc. (“Zyfer”),
+which developed and manufactured timing and synchronization products and which,
+prior to its incorporation, was operated as our Communications division. 
+Beginning in Fiscal 2003, we divested of certain of our business units
+in order to reduce our operating expenses and to focus on the operations of our
+Iteris Subsidiary. These divestitures and related restructuring activities
+included the following transactions: 
+· In March 2003, we
+ceased the development and sale of any new Broadcast products, and in
+September 2003, we sold the balance of our Broadcast business. 
+· In May 2003, we sold
+the assets of Zyfer for a purchase price of $2.3 million in cash and the
+assumption of liabilities, plus incentive payments based on the revenues
+generated by the sale of Zyfer’s products or the license of its technologies
+through April 2005. In October 2004, we received an incentive payment of
+$135,000 related to the twelve month period ended April 30, 2004, and in
+September 2005, we received an incentive payment of $83,000 related to the
+twelve month period ended April 30, 2005. 
+· In September 2003, we
+sold substantially all of the assets of MAXxess to an investor group that
+included one of our directors and certain members of the MAXxess management
+group. The consideration for the sale consisted of the assumption of $2.7
+million of liabilities, resulting in a net gain of $2.3 million on this sale.
+Subsequent to the sale, in 2005, another 
+member of our Board of Directors became the CEO of MAXxess. We currently
+sublease to MAXxess 10,000 square feet of space in our Anaheim facility. The
+sublease will terminate in September 2007 concurrently with the termination of
+the master lease for our Anaheim facility. 
+· In May 2004, we
+repurchased all of the outstanding shares of Series A preferred stock of
+the Iteris Subsidiary for an aggregate purchase price of approximately $17.5
+million in cash, and we purchased 548,000 shares of the Iteris Subsidiary
+common stock from DaimlerChrysler Ventures GmbH (“DCV”) in consideration for
+the issuance of 1.2 million shares of our common stock. We financed the
+purchase price for the Iteris Subsidiary Series A preferred stock through
+the issuance of convertible debentures in the original principal amount of
+$10.1 million, a $5.0 million term note payable to our bank and $2.4 million in
+cash. 
+· In June 2004, we issued
+2.6 million shares of our common stock valued at $8.6 million at the date of
+issuance in exchange for an aggregate of 1.3 million shares of common stock of
+the Iteris Subsidiary, which had the effect of reducing the residual minority
+interest in our Iteris Subsidiary to 8.1%. 
+· In October 2004, we
+merged the Iteris Subsidiary into us and the remaining minority interest in the
+Iteris Subsidiary (consisting of 1.2 million shares of common stock of the
+Iteris Subsidiary) was converted to 2.5 million shares of our common stock valued at $7.6
+million at the merger date. Immediately following the merger, we converted all
+of our outstanding Class B common stock (922,000 shares) into 1.0 million
+shares of our common stock (which was formerly designated as Class A common
+stock). In connection with this merger, we also assumed options and warrants to
+purchase an aggregate of 3.1 million and 327,000 shares, respectively, of the
+common stock of the Iteris Subsidiary, which became options and warrants to
+purchase an aggregate of 6.1 million and
+654,000 shares, respectively, of our common stock. 
+· In October 2004, we
+amended our certificate of incorporation to (a) change the voting rights
+of our Class A common stock from one-tenth to one vote per share,
+(b) remove the ability to issue any further shares of Class B common
+stock, and (c) rename our Class A common stock to common stock. As a
+result, we currently have only one class of capital stock outstanding, the
+common stock. 
+Our financial statements for all periods presented in this report have
+been restated to reflect the discontinuation of the operations of Broadcast,
+Zyfer and MAXxess. 
+We currently
+operate in three reportable segments: Roadway Sensors, Automotive Sensors and
+Transportation Systems. The Roadway Sensors segment includes our Vantage
+vehicle detection systems for traffic intersection control, 
+23 
+incident detection and
+certain highway traffic data collection applications. The Automotive Sensors
+segment is comprised of all activities related to our AutoVue LDW systems for
+vehicle safety. The Transportation Systems segment includes transportation
+engineering and consulting services and the development of transportation
+management and traveler information systems for the ITS industry. 
+Critical Accounting Policies and
+Estimates 
+Management’s
+Discussion and Analysis of Financial Condition and Results of Operations is
+based on our consolidated financial statements included herein, which have been
+prepared in accordance with generally accepted accounting principles in the
+United States (“GAAP”). The preparation of these financial statements requires
+management to make estimates and assumptions that affect the reported amounts
+of assets and liabilities and related disclosures of contingent assets and
+liabilities at the date of the financial statements and the reported amounts of
+revenues and expenses during the reporting period. On an ongoing basis, we
+evaluate these estimates and assumptions, including those related to the
+collectibility of accounts receivable, the valuation of inventories, the
+recoverability of long-lived assets and goodwill, the realizability of deferred
+tax assets, accounting for stock-based compensation, the valuation of equity
+instruments, warranty reserves and other contingencies. We base these estimates
+on historical experience and on various other factors that we believe to be
+reasonable under the circumstances, the results of which form the basis for
+making judgments about the carrying values of assets and liabilities that are
+not readily apparent from other sources. These estimates and assumptions by
+their nature involve risks and uncertainties, and may prove to be inaccurate.
+In the event that any of our estimates or assumptions are inaccurate in any
+material respect, it could have a material adverse effect on our reported
+amounts of assets and liabilities at the date of the financial statements and
+the reported amounts of revenues and expenses during the reporting period. 
+The following
+critical accounting policies affect our more significant judgments and estimates
+used in the preparation of our consolidated financial statements. 
+Revenue Recognition . We record product revenues and related costs
+of sales upon transfer of title, which is generally upon shipment or, if
+required, upon acceptance by the customer, provided that we believe
+collectibility of the net sales amount is reasonably assured. Accordingly, at the date revenue is
+recognized, the significant uncertainties concerning the sale have been
+resolved. 
+Contract revenues are derived primarily from long-term
+contracts with governmental agencies. 
+Contract revenues include costs incurred plus a portion of estimated
+fees or profits determined using the percentage of completion method of
+accounting based on the relationship of costs incurred to total estimated
+costs. Any anticipated losses on
+contracts are charged to earnings when identified. Changes in job performance and estimated
+profitability, including those arising from contract penalty provisions and
+final contract settlements, may result in revisions to recognized costs and
+revenues and are recognized in the period in which the revisions are
+determined. Profit incentives are
+included in revenue when their realization is reasonably assured. 
+In addition to product and contract revenues, we
+derive revenue from technology access fees, the provision of specific
+non-recurring contract engineering services related to our AutoVue LDW systems,
+and royalties related to unit sales of our AutoVue LDW systems by our strategic
+partner Valeo to the passenger car market. Technology access fee revenues are
+recognized evenly over the period in which they are earned. Non-recurring contract engineering revenues
+are recognized in the period in which the related services are performed. Royalty revenues are recorded based on unit
+sales of our products by Valeo and are recognized in the period in which such
+sales occur. Technology access fee
+revenues, contract engineering revenues and royalty revenues are included in
+net sales. 
+Revenues from follow-on service and support, for which
+we generally charge separately, are recorded in the period in which the
+services are performed. 
+Accounts Receivable . We estimate
+the collectibility of customer receivables on an ongoing basis by periodically
+reviewing invoices outstanding greater than a certain period of time. We record reserves for receivables deemed to
+be at risk for collection as well as a general reserve based on our historical
+collections experience. A considerable
+amount of judgment is required in assessing the ultimate realization of trade
+receivables, including the current credit-worthiness of each customer. If the financial condition of our customers
+deteriorates, resulting in an impairment of their ability to make required
+payments, additional allowances may be required that could adversely affect our
+operating results. 
+24 
+Inventory . Inventories consist of
+finished goods, work-in-process and raw materials and are stated at the lower
+of cost or market. We provide reserves
+for potentially excess and obsolete inventory. In assessing the ultimate
+realization of inventories, we make judgments as to future demand requirements
+and compare that with the current or committed inventory levels. Reserves are established for inventory levels
+that exceed anticipated future demand. It
+is possible that reserves over and above those already established may be
+required in the future if market conditions for our products deteriorate. 
+Goodwill . Goodwill is tested for impairment annually in
+our fourth fiscal quarter at the reporting unit level unless a change in
+circumstances indicates that more frequent impairment analysis is
+required. Impairment, if any, is
+measured based on the estimated fair value of the reporting units with the
+recorded goodwill. Fair value is
+determined by using the income approach methodology of valuation which utilizes
+discounted cash flows. Significant
+management judgment is required in the forecasts of future operating results
+that are used in the discounted cash flow method of valuation. In estimating future cash flows, we generally
+use the financial assumptions in our current budget and our current strategic
+plan, subject to modification as considered necessary, including sales and
+expense growth rates and the discount rates we estimate to represent our cost of
+funds. It is possible, however, that the
+plans and estimates used may be incorrect. 
+If our actual results, or the plans and estimates used in future
+impairment analyses, are lower than the original estimates used to assess the
+recoverability of goodwill, we could incur impairment charges. 
+Warranty. We generally provide a one to three year
+warranty from the original invoice date on all products, materials and
+workmanship. Defective products are
+either repaired or replaced, at our option, upon meeting certain criteria. We accrue a provision for the estimated costs
+that may be incurred for product warranties relating to a product as a
+component of cost of sales at the time revenue for that product is recognized. The accrued warranty provision is included
+within accrued expenses on the accompanying consolidated balance sheets. Should our actual experience of warranty
+returns be higher than anticipated, additional warranty reserves may be
+required, which may adversely affect our operating results. 
+Taxes. We recorded
+a valuation allowance to reduce our deferred tax assets to amounts that we
+believe are more likely than not to be realized. Realization of deferred tax
+assets (such as net operating loss carryforwards) is dependent on future
+taxable earnings and is therefore uncertain. On a quarterly basis, we assess
+the likelihood that our deferred tax asset balance will be recovered from
+future taxable income. To the extent we believe that recovery is not likely, we
+establish a valuation allowance against our deferred tax asset, increasing our
+income tax expense in the period such determination is made. 
+On an interim basis, we estimate what our anticipated
+annual effective tax rate will be and record a quarterly income tax provision
+in accordance with this anticipated rate. As the fiscal year progresses, we
+refine our estimates based upon actual events and earnings during the year.
+This estimation process can result in significant changes to our expected
+effective tax rate. When this occurs, we adjust the income tax provision during
+the quarter in which the change in estimate occurs so that the year-to-date
+provision reflects the expected annual rate. The changes described in the
+preceding sentence and adjustments to our valuation allowance may create
+fluctuations in our overall effective tax rate from quarter to quarter. 
+Stock-Based Compensation . We adopted Statement of Financial Accounting
+Standards (“SFAS”) No. 123 (revised 2004), Share-Based Payment 
+(“SFAS 123R”), effective April 1, 2006. 
+Prior to April 1, 2006, we followed the disclosure-only provisions of
+SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS
+123”), as amended by SFAS No. 148, Accounting for Stock-Based
+Compensation — Transition and Disclosure , and, accordingly,
+accounted for our stock-based compensation plans using the intrinsic value
+method under Accounting Principles Board Opinion No. 25 (“APB 25”) and related
+interpretations. 
+SFAS 123R requires all stock-based payments, including
+grants of employee stock options, to be recognized in the statement of
+operations as an expense, based on their grant date fair values with such fair
+values amortized over the requisite service period. We elected to utilize the modified
+prospective method for the transition to SFAS 123R. Under the modified
+prospective method, SFAS 123R applies to all awards granted or modified after
+the date of adoption. In addition, under the modified prospective method,
+compensation expense will be recognized for all stock-based compensation awards
+granted prior to but not yet vested as of April 1, 2006, based on grant-date
+fair values estimated in accordance with the original provisions of SFAS 123. 
+In implementing SFAS 123R, we have used the
+Black-Scholes-Merton (“BSM”) option-pricing formula to estimate the fair value
+of stock-based awards granted subsequent to April 1, 2006. Our assumptions under the BSM formula include
+the following: expected volatilities are
+based on the historical volatility of our stock price, the expected life of
+options is derived based on the historical life of our options, and the
+risk-free rate for periods within the expected life of the option is based on
+the 
+25 
+U.S. Treasury interest
+rates in effect at the time of grant. 
+Additionally, SFAS 123 did not require the estimation of forfeitures in
+the calculation of stock compensation expense; however, SFAS 123R does require
+such estimation and upon adoption of SFAS 123R, we changed our methodology to
+include an estimate of forfeitures. 
+Future stock-based compensation expense in any particular quarter or
+year could be affected by changes in our assumptions or changes in market
+conditions. 
+Results of Operations 
+The following table sets forth certain statement of operations data as
+a percentage of total net sales and contract revenues for the periods
+indicated. The following table should be read in conjunction with Management’s
+Discussion and Analysis of Financial Condition and Results of Operations. 
+Fiscal Year Ended March 31, 
+2007 
+2006 
+2005 
+Net sales and contract
+revenues: 
+Net sales 
+62.2 
+% 
+61.7 
+% 
+62.6 
+% 
+Contract revenues 
+37.8 
+38.3 
+37.4 
+Total net sales and contract
+revenues 
+100.0 
+% 
+100.0 
+% 
+100.0 
+% 
+Costs of net
+sales and contract revenues: 
+Cost of net sales (a) 
+34.0 
+32.7 
+34.3 
+Cost of contract revenues (a) 
+24.8 
+24.9 
+29.7 
+Gross profit 
+41.2 
+42.4 
+36.0 
+Operating expenses: 
+Selling, general and
+administrative (a) 
+27.6 
+30.4 
+45.3 
+Research and development (a) 
+6.9 
+10.3 
+13.4 
+Amotization of intangible
+assets 
+0.3 
+0.3 
+0.2 
+Deferred compensation expense
+(benefit) 
+(0.2 
+) 
+0.1 
+(1.0 
+) 
+Disposal of fixed assets 
+— 
+— 
+0.9 
+Acquired in-process research
+and development 
+— 
+— 
+0.3 
+Total operating expenses 
+34.6 
+41.1 
+59.2 
+Operating income (loss) 
+6.6 
+1.2 
+(23.2 
+) 
+Non-operating income (expense): 
+Other income (expense), net 
+(1.1 
+) 
+0.1 
+2.2 
+Interest expense, net 
+(2.7 
+) 
+(2.9 
+) 
+(2.5 
+) 
+Income (loss) before income taxes and minority interest 
+2.7 
+(1.6 
+) 
+(23.5 
+) 
+Income tax benefit 
+2.3 
+1.8 
+0.2 
+Minority interest in earnings of subsidiary 
+— 
+— 
+(1.1 
+) 
+Net
+income (loss) 
+5.0 
+% 
+0.2 
+% 
+(24.4 
+)% 
+(a) Includes stock-based
+compensation expense as a percent of total net sales and contract revenues as
+follows: 
+Cost of net sales 
+0.0 
+% 
+0.1 
+% 
+0.6 
+% 
+Cost of contract revenues 
+0.1 
+0.4 
+5.2 
+Selling, general and administrative expense 
+0.3 
+0.7 
+15.2 
+Research and development expense 
+0.0 
+0.3 
+4.4 
+Total stock-based compensation expense 
+0.5 
+% 
+1.4 
+% 
+25.4 
+% 
+Years Ended March 31, 2007, 2006
+and 2005 
+Net Sales and Contract Revenues .
+Net sales are comprised of Roadway Sensors sales, which are derived from sales
+of our Vantage video detection systems, and Automotive Sensors sales, which are
+derived from sales of AutoVue LDW systems, technology access fees, contract
+engineering revenue and royalty revenue generated from AutoVue related
+activities. Contract revenues consist entirely of Transportation Systems
+contract revenues, which are generated from systems integration and ITS
+consulting services with federal, state, county and municipal agencies. We
+currently have a diverse customer base with our 
+26 
+largest customer constituting 12.4% of total net sales
+and contract revenues in Fiscal 2007. Total net sales and contract revenues
+increased 15.5% to $58.3 million in Fiscal 2007 compared to $50.5 million in
+Fiscal 2006, and increased 8.8% in Fiscal 2006 from $46.4 million in Fiscal 2005. 
+Net sales increased 16.3% to $36.2 million in Fiscal
+2007 compared to $31.2 million in Fiscal 2006, and increased 7.2% in Fiscal
+2006 compared to $29.1 million in Fiscal 2005. The increase in net sales in
+each of the periods reflected increased unit sales in both Roadway Sensors and
+Automotive Sensors. 
+Roadway Sensors net sales
+comprised 75.2%, 72.0% and 75.4% of net sales in Fiscal 2007, Fiscal 2006 and
+Fiscal 2005, respectively and increased 21.5% to $27.3 million in Fiscal 2007
+compared to $22.4 million in Fiscal 2006 and increased 2.4% in Fiscal 2006
+compared to $21.9 million in Fiscal 2005. 
+The majority of Roadway Sensors net sales were derived from sales within
+North America. The Fiscal 2007 increase
+was primarily due to higher unit sales of Vantage video detection systems,
+which reflected broader market acceptance of video-based detection technologies
+and positive reaction to new Vantage product offerings such as color cameras
+and eAccess, as well as higher governmental spending, which we believe was
+related to the passage of the Federal Highway Bill in August 2005. The Fiscal 2006 increase was primarily due to
+increased market adoption of video-based detection technologies for traffic
+intersection management and our ability to obtain additional contracts with
+state departments of transportation. In
+Fiscal 2007, we experienced increased lead times in procuring components, a
+trend that we expect to continue and which could adversely affect our sales in
+the future. 
+Net
+sales from Automotive Sensors products and services increased 3.2% in Fiscal
+2007 to $9.0 million compared to $8.7 million in Fiscal 2006 and increased
+22.0% in Fiscal 2006 compared to $7.1 million in Fiscal 2005. The increase in Fiscal 2007 net sales of
+Automotive Sensors products and services was primarily related to increased
+unit sales of LDW systems in the North American commercial heavy truck
+market. While overall unit sales of our
+AutoVue LDW systems increased in Fiscal 2007, Automotive Sensors net sales were
+negatively affected by OEM volume discounts provided to our largest customer
+and the impact of the transition to our next generation AutoVue LDW systems for
+the heavy truck market in the latter part of Fiscal 2006. The Fiscal 2006 increase in Automotive Sensors
+net sales was largely due to increased LDW unit sales in the European and North
+American commercial heavy truck markets, which increased 35.6% in Fiscal 2006
+compared to Fiscal 2005. Although we
+have seen increased unit sales of AutoVue LDW systems in recent fiscal years,
+Automotive Sensors unit sales in Fiscal 2008 could be adversely impacted by
+slower than expected adoption rates of our LDW system by European and Asian OEM’s
+and North American heavy truck fleets, as well as potential additional OEM
+volume discounts. Additionally, recent
+environmental regulations in Europe and North America have substantially
+increased the cost of new commercial trucks, which could impact future truck
+sales volumes and, ultimately, unit sales of our LDW systems. 
+Royalty revenues from
+Valeo for sales of our LDW systems for the passenger car market remained
+relatively insignificant in Fiscal 2007. 
+Our LDW systems are now offered as an option on three Infiniti models. While Valeo is currently in discussions to
+offer our LDW systems on other passenger car platforms, we cannot assure you
+that Valeo will be successful in these efforts. 
+Contract revenues increased 14.1% to $22.0 million in
+Fiscal 2007 compared to $19.3 million in Fiscal 2006, and increased 11.5% in
+Fiscal 2006 compared to $17.3 million in Fiscal 2005. Contract revenues reflect
+a broad range of fixed price and cost plus fixed fee contracts for engineering
+study and design, systems integration and system implementation. All of our
+contract revenue is currently derived from work performed in North America.
+Contract revenues are dependent upon the continued availability of funding at
+both the state and federal levels from the various departments of
+transportation. We believe the increase
+in Fiscal 2007 contract revenues compared to Fiscal 2006 and Fiscal 2006
+compared to Fiscal 2005 was largely the result of the passage of the Federal
+Highway Bill in August 2005, as well as increased spending at the state
+and local levels. The increase in contract revenues in Fiscal 2007 was also due
+to continued growth in the California market and stronger sales in the Eastern
+U.S. market. In response to the growth
+in our Transportation Systems segment, we have increased our Transportation
+Systems staff by 16% in Fiscal 2007. We
+expect to continue to increase our Transportation Systems staff over the next
+fiscal year. We believe the ability of
+our Transportation Systems business to grow and successfully win and service
+new contracts will be highly dependent upon our continued success in recruiting
+and retaining qualified personnel. 
+Gross Profit .
+Total gross profit increased 12.2% to $24.0 million in Fiscal 2007 compared to
+$21.4 million in Fiscal 2006, and increased 28.2% in Fiscal 2006 compared to
+$16.7 million in Fiscal 2005. Total
+gross profit as a percent of net sales and contract revenues decreased to 41.2%
+in Fiscal 2007 compared to 42.4% in Fiscal 2006 and increased in Fiscal 2006
+from 36.0% in Fiscal 2005. 
+27 
+Gross profit as a percentage of net sales was 45.3% in
+Fiscal 2007 compared to 47.1% in Fiscal 2006 and 45.2% in Fiscal 2005. The 180 basis point decrease in gross profit
+in Fiscal 2007 compared to Fiscal 2006 was primarily due to volume discounts
+given to our largest Automotive Sensors hardware customer as well as an overall
+decline in unit volumes to this customer. 
+Fiscal 2007 gross profit as a percentage of net sales in our Roadway
+Sensors division were relatively consistent with Fiscal 2006 gross profit as a
+percentage of net sales. We limit quantitative discussion of gross profit for
+our Roadway Sensors and Automotive Sensors segments for competitive
+reasons. Gross profit as a percentage of
+net sales can fluctuate in any specific quarter or year based on customer mix and
+volume discounts given, as well as possible shifts of engineering resources
+from development activities to sustaining activities which we record as cost of
+goods sold. Gross profit as a percent of
+net sales has fluctuated over the last five years from a high of 51.0% in
+Fiscal 2003 to a low of 45.2% in Fiscal 2005. 
+The 190 basis point increase in gross profit in Fiscal
+2006 compared to Fiscal 2005 was primarily a result of increased margins on
+Roadway Sensors products due to product improvements aimed at reducing the cost
+of goods sold, production efficiencies as a result of higher unit sales and a
+change in our Roadway Sensors business model in California to a direct sales
+model. Additionally, Fiscal 2005 cost of net sales included $280,000 of stock
+based compensation compared to $27,000 in Fiscal 2006. 
+Gross profit as a percentage of contract revenues
+decreased to 34.4% in Fiscal 2007 compared to 34.8% in Fiscal 2006 and
+increased from 20.5% in Fiscal 2005. We recognize contract revenues and related
+gross profit using percentage of completion contract accounting and the
+underlying mix of contract activity affects the related gross profit recognized
+in any given period. The decrease in
+gross profit as a percent of contract revenues in Fiscal 2007 compared to
+Fiscal 2006 reflects a contract mix weighted more toward lower margin contracts
+in the period. The increase in Fiscal
+2006 from Fiscal 2005 was largely a result of the inclusion of $2.4 million of
+stock-based compensation in the cost of contract revenues in Fiscal 2005
+compared to $205,000 in Fiscal 2006. By
+comparison, $60,000 of stock-based compensation was included in Fiscal 2007
+cost of contract revenues. 
+Selling, General and Administrative
+Expense . Selling, general and administrative expense
+increased 4.8% to $16.1 million (or 27.6% of total net sales and contract
+revenues) in Fiscal 2007 compared to $15.4 million (or 30.4% of total net sales
+and contract revenues) in Fiscal 2006, and decreased 26.9% in Fiscal 2006
+compared to $21.0 million (or 45.3% of total net sales and contract revenues)
+in Fiscal 2005. The increase in selling, general and administrative expense in
+Fiscal 2007 compared to Fiscal 2006 was mainly a result of higher commissions
+associated with increased Roadway Sensors net sales and increased sales and
+marketing activities in our Transportation Systems segment. Additionally, selling, general and
+administrative expense included legal expenses associated with the settlement
+of litigation described in Note 7 to the accompanying consolidated financial
+statements, a severance accrual of approximately $300,000 associated with the
+departure of our former Chief Executive Officer in March 2007 and $180,000
+related to the write-off of past-due accounts receivable related to rent and
+other services provided to our former subsidiary, MAXxess. No further expense is expected to be incurred
+in connection with the aforementioned lawsuit or the severance arrangement with
+our former Chief Executive Officer. 
+Severance payments to our former Chief Executive Officer will be made
+over a one year period. We have written
+off all balances receivable from MAXxess based on our accounts receivable
+accounting policy and will continue to work with MAXxess to collect amounts due
+to us. Certain members of our Board of Directors
+are part of MAXxess management and ownership. In the coming quarters, we
+anticipate increased selling, general and administrative expense related to our
+efforts to comply with the internal control attestation requirements of the
+Sarbanes-Oxley Act, with which we must begin to comply in April 2007. 
+The decrease in selling, general and administrative
+expense in Fiscal 2006 compared to Fiscal 2005 was largely a result of a $7.1
+million charge for stock-based compensation incurred in Fiscal 2005, compared
+to stock-based compensation expense of $364,000 in Fiscal 2006; additional
+accounting and legal fees incurred in the first and second quarter of Fiscal
+2006 related to a change in audit firms; costs incurred in anticipation of
+compliance with the Sarbanes-Oxley Act of 2002; additional common area charges
+incurred in connection with our Anaheim headquarters; and increased outside
+sales commissions in our Roadway Sensors business. 
+Research and Development Expense .
+Research and development expense decreased 22.8% to $4.0 million (or 6.9% of
+total net sales and contract revenues) in Fiscal 2007 compared to $5.2 million
+(or 10.3% of total net sales and contract revenues) in Fiscal 2006, and
+decreased 16.3% in Fiscal 2006 compared to $6.2 million (or 13.4% of total net
+sales and contract revenues) in Fiscal 2005. The decrease in research and
+development expense in Fiscal 2007 compared to Fiscal 2006 was largely a result
+of higher than anticipated costs in the prior year period in Automotive Sensors
+as we expended significant development resources in qualifying the next
+generation LDW system with our largest customer, as well as several other heavy
+28 
+truck OEMs. Additionally, in Fiscal 2007, there was a
+shift in engineering resources from research and development activities to
+product support activities as a result of new product introductions and
+improvements in Roadway Sensors. Costs
+associated with product support activities are included in cost of net sales
+rather than research and development expense. 
+We plan to introduce several key products in our Roadway Sensors
+division in Fiscal 2008 and expect research and development expenses to
+increase slightly from Fiscal 2007 levels. 
+The decrease in research and development expense in
+Fiscal 2006 compared to Fiscal 2005 was mainly a result of $2.0 million of
+stock-based compensation charged to research and development expense in Fiscal
+2005 compared to stock-based compensation of $129,000 in Fiscal 2006. This effect was offset by increased spending
+in Fiscal 2006 for both our Vantage video detection products and our AutoVue
+LDW system for the heavy truck market. 
+Additional development funds were allocated to the Roadway Sensors
+business in Fiscal 2006 to complete the development of new products that were
+introduced in Fiscal 2007, refresh the existing product line and enhance cost
+reduction activities. Additional funds
+allocated to the Automotive Sensors business were primarily used to develop and
+qualify the next generation AutoVue LDW system for the heavy truck market in
+Europe and North America. 
+For competitive reasons, we closely guard the
+confidentiality of specific development projects. 
+Deferred
+Compensation Expense (Benefit). Deferred compensation expense
+(benefit) represents changes in the fair value of assets, primarily shares of
+our common stock, held by our deferred compensation savings plan under which
+certain senior executives may defer compensation. Prior to the merger of the
+Iteris Subsidiary into us in Fiscal 2005, the plan held shares of Iteris
+Subsidiary common stock. In connection
+with the Fiscal 2005 merger of the Iteris Subsidiary into us, shares of Iteris
+Subsidiary common stock held by the plan were exchanged for shares of our
+common stock. Changes in the value of common stock held by the plan resulted in
+a benefit of $91,000 in Fiscal 2007, expense of $48,000 in Fiscal 2006 and a
+benefit of $484,000 in Fiscal 2005. No
+compensation was deferred into the plan in Fiscal 2007, Fiscal 2006 and Fiscal
+2005. 
+Other Income (Expense), Net .
+Other income (expense), net reflects the following: 
+Year Ended March 31, 
+2007 
+2006 
+2005 
+(In thousands) 
+Settlement of lawsuits 
+$ 
+(635 
+) 
+$ 
+— 
+$ 
+949 
+Other 
+(18 
+) 
+35 
+105 
+Other income (expense),
+net 
+$ 
+(653 
+) 
+$ 
+35 
+$ 
+1,054 
+Other
+income (expense), net in Fiscal 2007 primarily reflects $635,000 of expense
+recorded in connection with the settlement of litigation in July 2006. Other income (expense), net in Fiscal 2005
+primarily reflects a $949,000 gain recognized on the settlement of litigation
+in which we were a beneficiary of, but not a party to, litigation between
+Rockwell International and the Michigan Department of Transportation. Refer to Note 7 to the accompanying
+consolidated financial statements for further discussion of these settlements. 
+Interest Expense, Net .
+Interest expense, net reflects the net of interest expense and interest income
+as follows: 
+Year Ended March 31, 
+2007 
+2006 
+2005 
+(In thousands) 
+Interest expense 
+$ 
+( 1,601 
+) 
+$ 
+( 1,461 
+) 
+$ 
+( 1,180 
+) 
+Interest income 
+1 
+2 
+2 
+Interest expense, net 
+$ 
+( 1,600 
+) 
+$ 
+( 1,459 
+) 
+$ 
+( 1,178 
+) 
+Interest
+expense, net increased 9.7% in Fiscal 2007 compared to Fiscal 2006 and
+increased 23.9% in Fiscal 2006 compared to Fiscal 2005. The increase in interest expense in Fiscal
+2007 compared to Fiscal 2006 was mainly related to the October 2006 banking
+change, in which we refinanced our existing term note and line of credit with a
+new bank. In connection with this refinancing, we also increased our credit
+facility by $3.0 million from $5.0 million to $8.0 million, which resulted in
+slightly higher interest costs in Fiscal 2007 as compared to Fiscal 2006. The increase in interest expense, net in
+Fiscal 2006 as compared to Fiscal 2005 was mainly related to an increase in the
+interest rate on our line of credit and term note as well as increased average
+borrowings on our line of credit. 
+29 
+Income Taxes .
+During Fiscal 2007, we recognized an income tax benefit of $1.3 million and at
+March 31, 2007, our consolidated balance sheet included net deferred tax
+assets of $3.0 million. The ability to record the deferred tax asset was based
+on the more likely than not criteria of Statement of Financial Accounting
+Standards (“SFAS”) No. 109, Accounting for Income
+Taxes . During Fiscal 2006, we
+recognized an income tax benefit of $885,000, and at March 31, 2006, our
+consolidated balance sheet included net deferred tax assets of $1.6 million. 
+At March 31, 2007, we had $49.3 million of
+federal net operating loss carryforwards and $22.4 million of state net
+operating loss carryforwards that begin to expire in 2019 and 2008,
+respectively. Due to changes in stock ownership, our federal net operating loss
+carryforwards are subject to a Section 382 limitation estimated at
+approximately $2.9 million annually which can be utilized to offset federal
+consolidated taxable income. 
+Although the impact cannot be precisely determined, we
+believe that our net operating loss carryforwards and the valuation allowance
+we have recorded against our net deferred tax assets in our consolidated
+balance sheets will cause us to have future income tax payments and income tax
+expense that are substantially lower than the income tax liability and income
+tax expense calculated using statutory tax rates. 
+Minority Interest in Earnings of
+Subsidiary . Minority interest in earnings of subsidiary
+represents the minority stockholders’ share of the Iteris Subsidiary’s net
+income (loss) combined with the accretion of the redemption preference of the
+Iteris Subsidiary’s Series A preferred stock. On October 22, 2004, we
+completed the merger of the Iteris Subsidiary into us. As a result of the
+completion of the merger in October 2004, we did not incur any charge for
+minority interest subsequent to that date. 
+No future charges for minority interest are anticipated. 
+Stock-Based Compensation Expense . In Fiscal 2007, we adopted SFAS 123R using
+the modified prospective approach. Stock-based compensation expense was $288,000
+in Fiscal 2007. See Notes 1 and 10 to
+the accompanying consolidated financial statements for additional discussion
+regarding our implementation of SFAS 123R. 
+As discussed above and in the Overview to Management’s
+Discussion and Analysis of Financial Condition and Results of Operations and in
+Note 3 to the accompanying consolidated financial statements, on
+October 22, 2004, we completed the merger of the Iteris Subsidiary into
+us. Upon completion of the merger, we
+recorded $11.3 million of stock-based compensation expense related to the
+assumption and exchange of vested stock options assumed in the merger. Additionally, stock-based compensation
+expense was recorded subsequent to the merger date based on the vesting
+schedule of stock options that were not yet vested on the merger date. This resulted in stock-based compensation
+expense of $725,000 and $11.8 million in Fiscal 2006 and Fiscal 2005,
+respectively. No additional stock-based
+compensation expense is expected to be recognized in connection with stock
+options assumed in the merger. 
+Liquidity
+and Capital Resources 
+Cash
+Flows 
+We have
+historically financed our operations with a combination of cash flows from
+operations, borrowings under credit facilities and the sale of equity
+securities. We currently rely on cash flows from operations and borrowings on a
+line of credit facility to fund our operations, which we believe to be
+sufficient to fund our operations for at least the next twelve months. However,
+should a shortfall occur, we believe we could obtain additional funds through
+additional borrowings or the sale of equity securities. At March 31, 2007,
+we had $7.0 million in working capital, which included borrowings of $4.0
+million on our revolving line of credit and $35,000 in cash and cash
+equivalents. This compares to working capital of $3.0 million at March 31,
+2006, which included borrowings of $2.7 million on our revolving line of credit
+and $131,000 in cash and cash equivalents. Our operations used $2.0 million of
+cash during Fiscal 2007, primarily as a result of investments in inventory due
+to sales growth and longer lead times in procuring certain compenents, and an
+increased level of net costs and estimated earnings in excess of billings due
+to sales growth and the timing of invoicing on contracts in our Transportation
+Systems segment. These were partially
+offset by net income of $2.9 million. 
+During Fiscal 2006, our operations provided $218,000 of cash, primarily
+as a result of planned decreases in inventory and the timing of payments on
+accrued expenses and payables, which were partially offset by increases in
+accounts receivable and net costs and estimated earnings in excess of billings
+on uncompleted contracts, both as a result of sales growth. We generated $590,000 in cash from operations
+in Fiscal 2005, primarily due to the receipt of $949,000 related to a legal
+settlement between Rockwell International and the Michigan Department of
+Transportation, to which we were a third party beneficiary. 
+30 
+Investing
+activities for Fiscal 2007, Fiscal 2006 and Fiscal 2005 consisted primarily of
+purchases of property and equipment, which aggregated $488,000, $1.3 million
+and $670,000, respectively. In Fiscal
+2006, capital expenditures increased significantly primarily due to hardware,
+software and related labor costs to implement a new enterprise resource
+management system, which was put into use at the beginning of Fiscal 2007. 
+Cash provided by
+financing activities was $2.4 million in Fiscal 2007, which was the net
+result of net payments on borrowings of $1.2 million offset by cash inflows of
+$3.6 million from the exercise of outstanding stock options and warrants to
+purchase our common stock. As discussed in Note 9 to the accompanying
+consolidated financial statements, approximately $2.0 million of the $3.6
+million in proceeds from the exercise of stock options and warrants was raised
+through the exercise of outstanding warrants to purchase an aggregate of
+1,250,000 shares of our common stock. 
+During Fiscal 2006, financing activities provided $1.1 million of cash
+as a result of net borrowings of $792,000 and cash inflows of $333,000 from the
+exercise of outstanding stock options and warrants to purchase our common
+stock. During Fiscal 2005, financing
+activities used $2.5 million of cash, which was comprised of net cash outflows
+of approximately $3.1 million related to the merger activities described more
+fully above in the Overview to Management’s Discussion and Analysis of
+Financial Condition and Results of Operations and in Note 3 to the accompanying
+consolidated financial statements, partially offset by $501,000 in proceeds
+from the exercise of stock options and warrants to purchase our common stock. 
+Borrowings 
+The following table summarizes our borrowings and
+long-term debt: 
+At March 31, 2007 
+(In thousands) 
+Revolving line of
+credit 
+$ 
+4,015 
+Convertible debentures,
+net 
+9,410 
+Bank term note 
+1,573 
+Promissory note to
+landlord 
+646 
+Other long-term debt 
+78 
+$ 
+15,722 
+In October 2006,
+we refinanced our existing line of credit and entered into a new two-year
+credit facility with our new bank. The
+facility provides for combined line of credit and term note borrowings of up to
+$8.0 million. Under the new credit
+facility, we may borrow against our eligible accounts receivable and eligible
+inventory, as defined in the credit agreement. 
+Interest on borrowed amounts is payable monthly at the current stated
+prime rate plus 1.25%. Additionally, we
+are obligated to pay an unused line fee of 0.25% per annum applied to the
+amount by which the maximum credit amount exceeds the average daily principal
+balance during the preceding month. The new credit facility requires $2,000 in
+monthly collateral management fees and includes an early termination fee equal
+to 2% of the total facility during the first year of the agreement and 1% of
+the total facility in the second year of the agreement. Additionally, we paid a
+commitment fee of $40,000 in October 2006 and are obligated to pay an
+additional $40,000 on the one year anniversary of the facility. The new credit
+facility is secured by substantially all of our assets. At March 31, 2007, we had $8.0 million
+available under our credit facility, of which $2.4 million was unused. 
+We believe that
+the cash generated from our operations, together with our new credit facility,
+will be sufficient to fund our operations for at least the next twelve months.
+However, should a shortfall occur, we may need to raise additional funds
+through other debt financings or the sale of equity securities. 
+Contractual
+Obligations 
+Our contractual obligations are as follows at
+March 31, 2007: 
+Payments Due by Period 
+2008 
+2009 
+2010 
+2011 
+2012 
+Thereafter 
+Total 
+(In thousands) 
+Lines of credit 
+$ 
+4,015 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+4,015 
+Notes payable 
+1,947 
+350 
+— 
+— 
+— 
+— 
+2,297 
+Convertible debentures 
+— 
+— 
+9,850 
+— 
+— 
+— 
+9,850 
+Operating leases 
+1,277 
+1,398 
+1,391 
+1,348 
+1,332 
+3,823 
+10,569 
+Total 
+$ 
+7,239 
+$ 
+1,748 
+$ 
+11,241 
+$ 
+1,348 
+$ 
+1,332 
+$ 
+3,823 
+$ 
+26,731 
+31 
+At March 31, 2007, we had firm commitments to
+purchase inventory in the amount of $2.6 million during the first and second
+quarters of Fiscal 2008. 
+Off Balance Sheet Arrangements 
+In
+connection with the restructuring and merger activities described in the Overview
+to Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Notes 3, 5
+and 9 to the accompanying consolidated financial statements, in May 2004 we
+issued subordinated convertible debentures in an aggregate original principal
+amount of $10.1 million. These debentures are due in full on May 19, 2009
+and are convertible into shares of our common stock at a conversion price of
+$3.61 per share. At March 31, 2007, $9.9 million of these convertible
+debentures remained outstanding. Because these debentures are conventionally
+convertible, we have not separately accounted for the conversion feature and,
+accordingly, no separate amounts are presented in our consolidated financial
+statements in connection with this conversion feature. 
+At
+March 31, 2007, outstanding warrants to purchase 62,500 shares of our common
+stock at an exercise price of $1.95 per share and outstanding warrants to
+purchase an aggregate of 246,250 shares of common stock at an exercise
+price of $3.25 per share are callable by us if the market price of our common
+stock trades for 20 consecutive days at a price equal to or greater than two
+times the exercise price of the warrants. Outstanding w arrants to
+purchase an aggregate of 75,000 shares of our common stock at an exercise
+price of $5.00 per share are callable by us if the market price of our common
+stock trades for 20 consecutive days at a price equal to or greater than
+one and a half times the exercise price of the warrants. 
+In connection with the issuance of warrants to
+purchase 246,250 shares of our common stock at $3.25 per share, we are a party
+to a registration rights agreement that contains provisions under which we
+could be subjected to liquidated damages should we fail to maintain effective
+registration statements for the shares of common stock issuable upon exercise
+of certain underlying warrants. These
+warrants have been accounted for within equity in our consolidated balance
+sheet at March 31, 2007 in accordance with EITF 00-19, Accounting
+for Derivative Financial Instruments Indexed to, and Potentially Settled in, a
+Company’s Own Stock , and, accordingly, no liabilities have been
+recorded in connection therewith. As of
+the date of this filing, no liquidated damages are payable under the provisions
+of the registration rights agreement associated with these warrants. 
+Rule
+10b5-1 Trading Plans 
+Two of
+our executive officers, Greg McKhann and Francis Memole, have entered into
+trading plans pursuant to Rule 10b5-1(c)(1) of the Securities Exchange Act of
+1934, as amended, which cover an aggregate of 150,000 shares of our common
+stock. Abbas Mohaddes terminated his
+trading plan upon his promotion to Chief Executive Officer in March 2007. 
+Recent Accounting
+Pronouncements 
+In July 2006, the Financial Accounting Standards Board
+(the “FASB”) issued FASB Interpretation No. 48, Accounting
+for Uncertainty in Income Taxes (“FIN 48”). FIN 48 clarifies the accounting and reporting
+for income taxes recognized in accordance with SFAS No. 109, Accounting for Income Taxes . 
+This Interpretation prescribes a comprehensive model for the financial
+statement recognition, measurement, presentation and disclosure of uncertain
+tax positions taken or expected to be taken in income tax returns. We are currently evaluating the impact of FIN
+48 and will adopt this Interpretation in the first quarter of our fiscal year
+ending March 31, 2008. 
+In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS 157”), which defines fair
+value, establishes a framework for measuring fair value, and expands disclosure
+about fair value measurements. SFAS 157 does not require any new fair value
+measurements; rather it specifies valuation methods to be applied when fair
+value measurements are required under existing or future accounting
+pronouncements. SFAS 157 is effective for fiscal years beginning after November
+15, 2007, and interim periods within those fiscal years. Early application of
+the statement is encouraged. Generally, this statement will be applied
+prospectively. We are currently
+evaluating the impact of SFAS 157 and expect to adopt SFAS 157 in the first
+quarter of our fiscal year ending March 31, 2009. 
+In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities —
+Including an Amendment of FASB Statement No. 115 (“SFAS 159”). SFAS
+159 permits entities to choose to measure many financial instruments and
+certain other items at fair value. Unrealized gains and losses on items for
+which the fair value option has been elected will be recognized in earnings at
+each subsequent reporting date. SFAS 159 is effective for financial statements
+issued for fiscal years beginning after November 15, 2007. We are evaluating the impact that the
+adoption of SFAS 159 will have on our results of operations and financial
+condition and expect to adopt SFAS 159 in our fiscal year ending March 31,
+2009. 
+Seasonality 
+We have historically experienced seasonality,
+particularly with respect to our Roadway Sensors net sales in the third and
+fourth fiscal quarters due to a reduction in road construction or repairs
+during the winter months due to inclement weather conditions. 
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
+MARKET RISK 
+Our
+exposure to interest rate risk is limited to our line of credit, bank term note
+and a promissory note to our landlord. Our line of credit, bank term note and
+promissory note to our landlord bear interest based on the prevailing prime
+rate (8.25% 
+31 
+at March 31,
+2007). We do not believe that a 10%
+increase in the interest rate on our line of credit, bank term note and
+promissory note to our landlord (from 9.50% to 10.45% on the line of credit,
+from 9.50% to 10.45% on the bank term note and from 10.25% to 11.28% on the
+promissory note to our landlord) would have a material impact on our financial
+position, operating results or cash flows. In addition, we believe that the
+carrying value of our outstanding debt approximates fair value. 
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+The financial
+statements and supplementary data required by Regulation S-X are included in
+Part IV, Item 15 of this report. 
+ITEM 9. CHANGES IN AND
+DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+None. 
+ITEM 9A. CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Controls and
+Procedures 
+As of the end of
+the period covered by this report, we carried out an evaluation, under the
+supervision and with the participation of our management, including our Chief
+Executive Officer and our Chief Financial Officer, of the effectiveness of the
+design and operation of our disclosure controls and procedures, as such term is
+defined in Exchange Act Rules 13a-15(e) and 15d-15(e). Based upon that
+evaluation, the Chief Executive Officer and Chief Financial Officer concluded
+that our disclosure controls and procedures are effective to ensure that
+information required to be disclosed by us in the reports that we file or
+submit under the Exchange Act is recorded, processed, summarized and reported
+within the time periods specified in the Securities and Exchange Commission’s
+rules and forms and are effective in ensuring that information required to be
+disclosed by us in the reports that we file or submit under the Exchange Act is
+accumulated and communicated to our management, including our Chief Executive
+Officer and Chief Financial Officer, as appropriate, to allow timely decisions
+regarding required disclosure. In designing and evaluating the disclosure
+controls and procedures, our management recognized that any controls and
+procedures, no matter how well designed and operated, can provide only
+reasonable assurance of achieving the desired control objectives. Our
+management necessarily applied its judgment in evaluating the cost-benefit
+relationship of such controls and procedures. 
+Changes in Internal Controls 
+During the most recent
+completed fiscal quarter covered by this report, there has been no change in
+our internal controls over financial reporting (as defined in Rules 13a-15(f) and
+15d-15(f) under the Securities Exchange Act of 1934) that has materially
+affected, or is reasonably likely to materially affect, our internal controls
+over financial reporting. 
+Effective April 1, 2006,
+we implemented a new enterprise resource planning system that we believe has
+not resulted in any material changes in our internal controls over financial
+reporting. 
+ITEM 9B . OTHER INFORMATION 
+None. 
+PART III 
+ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
+GOVERNANCE 
+(a) Identification of Directors. The
+information under the caption “Election of Directors,” appearing in our proxy
+statement for the 2007 Annual Meeting of Stockholders, is incorporated herein
+by reference. 
+(b) Identification of Executive Officers. The
+information under the caption “Executive Compensation and Other Information -
+Executive Officers,” appearing in our proxy statement for the 2007 Annual
+Meeting of Stockholders, is incorporated herein by reference. 
+32 
+(c) Compliance with Section 16(a) of the
+Exchange Act. The information under the caption “Section 16(a) Beneficial
+Ownership Reporting Compliance” appearing in our proxy statement for the 2007
+Annual Meeting of Stockholders is incorporated herein by reference. 
+(d) Corporate Governance . The information
+under the caption “Corporate Governance,” appearing in our proxy statement for
+the 2007 Annual Meeting of Stockholders, is incorporated herein by reference. 
+(e) Audit Committee . The information under the
+caption “Board Meetings and Committees – Audit Committee,” appearing in our
+proxy statement for the 2007 Annual Meeting of Stockholders, is incorporated
+herein by reference. 
+ITEM 11. EXECUTIVE
+COMPENSATION 
+The information
+under the caption “Executive Compensation and Other Information,” appearing in
+our proxy statement for the 2007 Annual Meeting of Stockholders, is
+incorporated herein by reference. 
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
+AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+The information
+under the captions “Equity Compensation Plans” and “Principal Stockholders and
+Common Stock Ownership of Certain Beneficial Owners and Management,” appearing
+in our proxy statement for the 2007 Annual Meeting of Stockholders, is
+incorporated herein by reference. 
+ITEM 13. CERTAIN
+RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+The information
+under the captions “Corporate Governance – Director Independence” and “Certain
+Transactions,” appearing in our proxy statement for the 2007 Annual Meeting of
+Stockholders, is incorporated herein by reference. 
+ITEM 14. PRINCIPAL
+ACCOUNTING FEES AND SERVICES 
+The information
+under the caption “Fees Paid to Independent Registered Public Accounting Firm,”
+appearing in our proxy statement for the 2007 Annual Meeting of Stockholders,
+is incorporated herein by reference. 
+PART IV 
+ITEM 15. EXHIBITS
+AND FINANCIAL STATEMENT SCHEDULES 
+(a) Documents
+filed as part of this report: 
+1. Financial Statements. The following
+financial statements of Iteris, Inc. are included in a separate
+section of this Annual Report on Form 10-K commencing on the
+pages referenced below: 
+Report of Independent
+Registered Public Accounting Firm 
+Consolidated Balance
+Sheets as of March 31, 2007 and 2006 
+Consolidated
+Statements of Operations for the years ended March 31, 2007, 2006 and
+2005 
+Consolidated
+Statements of Stockholders’ Equity and Comprehensive Income for the years
+ended March 31, 2007, 2006 and 2005 
+Consolidated
+Statements of Cash Flows for the years ended March 31, 2007, 2006 and
+2005 
+Notes to
+Consolidated Financial Statements 
+2. Financial Statement Schedules . 
+Schedule II — Valuation
+and Qualifying Accounts 
+All other schedules have
+been omitted because they are not required or the required information is
+included in our consolidated financial statements and notes thereto. 
+33 
+3. Exhibits . 
+The following exhibits
+are filed herewith or incorporated by reference to the location indicated
+below: 
+Exhibit 
+Number 
+Description 
+Where Located 
+3.1 
+Amended and Restated Certificate of Incorporation of
+the registrant 
+Exhibit 3.1 to the registrant’s Current
+Report on Form 8-K as filed with the SEC on October 28, 2004 
+3.2 
+Bylaws of the registrant, as amended 
+Exhibit 4.2 to the registrant’s Registration
+Statement on Form S-1 (Reg. No. 033-67932) as filed with
+the SEC on July 6, 1993 
+3.3 
+Certificates of Amendment to Bylaws of the
+registrant dated April 24, 1998 and August 10, 2001 
+Exhibit 3.4 to the registrant’s Annual
+Report on Form 10-K/A for the year ended March 31, 2003 as
+filed with the SEC on July 29, 2003 
+3.4 
+Certificate of Amendment to Bylaws of registrant
+dated September 9, 2004 
+Exhibit 3.1 to the registrant’s Quarterly Report
+on Form 10-Q for the quarter ended September 30, 2004 as filed with the SEC
+on November 15, 2004 
+3.5 
+Certificate of Amendment to Bylaws of registrant
+effective September 16, 2005 
+Filed Herewith 
+4.1 
+Specimen of common stock certificate 
+Exhibit 4.1 to registrant’s Registration
+Statement on Form 8-A as filed with the SEC on December 8, 2004 
+4.2 
+Amended and Restated Rights Agreement, dated as of
+May 10, 2004, by and between the registrant and U.S. Stock Transfer
+Corporation, including exhibits thereto 
+Exhibit 99.1 to the registrant’s Registration
+Statement on Form 8-A/A as field with the SEC on June 18, 2004 
+10.1* 
+Profit Sharing Plan and Trust 
+Exhibit 10.3 to the registrant’s Amendment
+No. 2 to the Registration Statement on Form S-8 (Reg.
+No. 002-98656) as filed with the SEC on May 5, 1988 
+10.2* 
+Amendment Nos. 3 and 4 to the Profit Sharing Plan
+and Trust 
+Exhibits 4.3.1 and 4.3.2, respectively, to
+Amendment No. 3 to the registrant’s Registration Statement on
+Form S-3 (Reg. No. 002-86220) as filed with the SEC on
+June 13, 1990 
+10.3* 
+Form of Executive Deferral Plan between the
+registrant and certain employees of the registrant 
+Exhibit 10.4 to the registrant’s Annual
+Report on Form 10-K for the year ended March 31, 1988 
+10.4 
+Form of Indemnity Agreement entered into by the
+registrant and certain of its officers and directors 
+Exhibit 19.4 to the registrant’s Quarterly
+Report on Form 10-Q for the quarter ended September 30, 1988 
+10.5 
+Form of Indemnification Agreement entered into
+by the registrant and certain of its officers and directors 
+Exhibit 10.5 to the registrant’s Annual
+Report on Form 10-K for the year ended March 31, 2004 as
+filed with the SEC on June 29, 2004 
+10.6* 
+1997 Stock Incentive Plan (as amended on May 3,
+2003, as further amended on December 15, 2004) 
+Exhibit 10.32 to the registrant’s Annual
+Report on Form 10-K for the year ended March 31, 2005 as
+filed with the SEC on July 14, 2005 
+10.7* 
+Form of Notice of Grant of Stock Option 
+Exhibit 99.2 to the registrant’s
+Registration Statement on Form S-8 (File No. 333-30396)
+as filed with the SEC on February 14, 2000 
+34 
+Exhibit 
+Number 
+Description 
+Where Located 
+10.8* 
+Form of Stock Option Agreement 
+Exhibit 99.3 to the registrant’s
+Registration Statement on Form S-8 (File No. 333-30396)
+as filed with the SEC on February 14, 2000 
+10.9* 
+Form of Addendum to Stock Option
+Agreement—Involuntary Termination Following Corporate Transaction or Change
+in Control 
+Exhibit 99.4 to the registrant’s
+Registration Statement on Form S-8 (File No. 333-30396)
+as filed with the SEC on February 14, 2000 
+10.10* 
+Form of Addendum to Stock Option
+Agreement—Limited Stock Appreciation Rights 
+Exhibit 99.5 to the registrant’s
+Registration Statement on Form S-8 (File No. 333-30396)
+as filed with the SEC on February 14, 2000 
+10.11* 
+Form of Stock Issuance Agreement 
+Exhibit 99.6 to the registrant’s
+Registration Statement on Form S-8 (File No. 333-30396)
+as filed with the SEC on February 14, 2000 
+10.12* 
+Form of Addendum to Stock Issuance Agreement—Involuntary
+Termination Following Corporate Transaction/Change in Control 
+Exhibit 99.7 to the registrant’s
+Registration Statement on Form S-8 (File No. 333-30396)
+as filed with the SEC on February 14, 2000 
+10.13* 
+Form of Notice of Grant of Automatic Stock
+Option—Initial Grant 
+Exhibit 99.8 to Exhibit 99.8 to
+registrant’s Registration Statement on Form S-8 (File No. 333-30396)
+as filed with the SEC on February 14, 2000 
+10.14* 
+Form of Notice of Grant of Automatic Stock
+Option—Annual Grant 
+Exhibit 99.9 to the registrant’s Registration
+Statement on Form S-8 (File No. 333-30396) as filed
+with the SEC on February 14, 2000 
+10.15* 
+Form of Automatic Stock Option Agreement. 
+Exhibit 99.10 to the registrant’s
+Registration Statement on Form S-8 (File No. 333-30396)
+as filed with the SEC on February 19, 2000 
+10.16 
+Amended and
+Restated Agreement of Purchase and Sale and Escrow Instructions, dated
+February 19, 2002, by and between Iteris, Inc. and 1515 South
+Manchester, LLC 
+Exhibit 2.1
+to the registrant’s Current Report on Form 8-K as filed with the
+SEC on June 12, 2002 
+35 
+10.17* 
+Change in
+Control Agreement dated May 8, 2003 by and between the registrant and
+Gregory A. Miner 
+Exhibit 10.1
+to the registrant’s Quarterly Report on Form 10-Q for the quarter
+ended June 30, 2003 as filed with the SEC on August 14, 2003 
+10.18* 
+Change in
+Control Agreement dated May 20, 2003 by and between the registrant and
+Jack E. Johnson 
+Exhibit 10.23
+to Amendment No. 1 to the registrant’s Registration Statement on
+Form S-1 as filed with the SEC on February 17, 2004 
+10.19* 
+Iteris Inc. 1998
+Stock Incentive Plan (as amended on February 7, 2000) 
+Exhibit 10.24
+to the registrant’s Annual Report on Form 10-K for the year ended
+March 31, 2005 as filed with the SEC on July 14, 2005 
+10.20* 
+Form of Notice
+of Grant, including forms of Option Agreement and Stock Purchase Agreement
+for the following directors and executive officers: Gary Hernandez, Dr.
+Hartmut Marwitz, Paul E. Wright, Jack Johnson, Richard D. Crawshaw, Gregory
+McKhann, Francis Memole, James S. Miele, Abbas Mohaddes and Stephen Edwin
+Rowe 
+Exhibit
+99.2 to the registrant’s Registration Statement on Form S-8 (File No. 333-126834) as
+filed with the SEC on July 22,
+2005 
+10.21* 
+Form of Addendum
+to Stock Option Agreement 
+Exhibit
+99.3 to the registrant’s Registration Statement on Form S-8 (File No. 333-126834) as
+filed with the SEC on July 22,
+2005 
+10.22* 
+Form of 1997
+Stock Option Agreements 
+Exhibit
+99.4 to the registrant’s Registration Statement on Form S-8 (File No. 333-126834) as
+filed with the SEC on July 22,
+2005 
+10.23* 
+Iteris, Inc.
+Deferred Compensation Savings Plan and Grantor Trust 
+Exhibit 10.31
+to the registrant’s Annual Report on Form 10-K for the year ended
+March 31, 2005 as filed with the SEC on July 14, 2005 
+10.24+ 
+Cooperative
+Agreement for Development, Manufacture, Marketing and Sale of Products to the
+Class 1 and Class 2 Vehicle Markets Incorporating Iteris’ LDWS
+Technology (Valeo Schalter and Sensoren GmbH) 
+Exhibit 10.1
+to the registrant’s Quarterly Report on Form 10-Q for the quarter
+ended June 30, 2004 as filed with the SEC on August 16, 2004 
+10.25 
+Warrant Exercise
+Agreement dated September 27, 2006 by and among the registrant and Special
+Situations Fund III QP, L.P., Special Situations Fund III, L.P., Special
+Situations Cayman Fund, L.P. and Special Situations Private Equity Fund, L.P. 
+Exhibit
+10.1 to the registrants’s Quarterly Report on Form 10-Q for the quarter ended
+September 30, 2006 as filed with the SEC on November 14, 2006. 
+10.26 
+Registration
+Rights Agreement dated September 28, 2006 by and among the registrant and
+Special Situations Fund III QP, L.P., Special Situations Fund III, L.P.,
+Special Situations Cayman Fund, L.P. and Special Situations Private Equity
+Fund, L.P. 
+Exhibit
+10.2 to the registrants’s Quarterly Report on Form 10-Q for the quarter ended
+September 30, 2006 as filed with the SEC on November 14, 2006. 
+36 
+10.27+ 
+National
+Intelligent Transportation Systems (ITS) Architecture Evolution and Support
+Award/Contract effective as of October 1, 2006 by and between the registrant
+and the Federal Highway Administration 
+Exhibit
+10.3 to the registrants’s Quarterly Report on Form 10-Q for the quarter ended
+September 30, 2006 as filed with the SEC on November 14, 2006. 
+10.28 
+Loan and
+Security Agreement effective as of October 16, 2006 by and between the
+registrant and Silicon Valley Bank 
+Exhibit
+10.4 to the registrants’s Quarterly Report on Form 10-Q for the quarter ended
+September 30, 2006 as filed with the SEC on November 14, 2006. 
+37 
+Exhibit 
+Number 
+Description 
+Where Located 
+10.29 
+Intellectual Property Security Agreement dated
+October 9, 2006 by and between the registrant and Silicon Valley Bank 
+Exhibit 10.5 to the registrants’s Quarterly
+Report on Form 10-Q for the quarter ended September 30, 2006 as filed with
+the SEC on November 14, 2006. 
+10.30+ 
+Settlement Agreement, effective August 15, 2006, by
+and between the registrant and Delta Networks, Inc. 
+Exhibit 10.1 to the registrant’s Current Report
+on Form 8-K as filed with the SEC on August 21, 2006 
+10.31* 
+Offer letter effective February 28, 2007 by and
+between the registrant and Abbas Mohaddes 
+Exhibit 10.1 to the registrant’s Current Report
+on Form 8-K as filed with the SEC on March 6, 2007 
+10.32* 
+Separation Agreement and Release of Claims dated
+March 1, 2007 by and between the registrant and Jack Johnson 
+Exhibit 10.2 to the registrant’s Current Report
+on Form 8-K as filed with the SEC on March 6, 2007 
+21 
+Subsidiaries of
+the registrant 
+Filed
+Herewith 
+23 
+Consent of
+Independent Registered Public Accounting Firm 
+Filed
+Herewith 
+31.1 
+Certification of
+the Chief Executive Officer Pursuant to Section 302 of the
+Sarbanes-Oxley Act of 2002 
+Filed
+Herewith 
+31.2 
+Certification of
+the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley
+Act of 2002 
+Filed
+Herewith 
+32.1 
+Certification of
+the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as
+Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 
+Filed
+Herewith 
+32.2 
+Certification of
+the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as
+Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 
+Filed
+Herewith 
+* Indicates a
+management contract or compensatory plan or arrangement 
++ Confidential treatment has been requested for
+certain confidential portions of this exhibit pursuant to Rule 24b-2
+of the Securities Exchange Act of 1934, as amended. In accordance with
+Rule 24b-2, these confidential portions have been omitted from the
+exhibit and filed separately with the SEC. 
+38 
+SIGNATURES 
+Pursuant to the
+requirements of Section 13 or 15(d) of the Securities Exchange Act of
+1934, the registrant has duly caused this report to be signed on its behalf by
+the undersigned, thereunto duly authorized. 
+ITERIS, INC. 
+(Registrant) 
+By 
+/s/ ABBAS MOHADDES 
+Abbas Mohaddes 
+President and Chief Executive Officer 
+39 
+POWER OF ATTORNEY 
+We, the
+undersigned officers and directors of Iteris, Inc., do hereby constitute
+and appoint James S. Miele and Abbas Mohaddes, and each of them, our true and
+lawful attorneys-in-fact and agents, each with full power of substitution and
+resubstitution, for him and in his name, place and stead, in any and all
+capacities, to sign any and all amendments to this report, and to file the
+same, with exhibits thereto, and other documents in connection therewith, with
+the Securities and Exchange Commission, granting unto said attorneys-in-fact
+and agents, and each of them, full power and authority to do and perform each
+and every act and thing requisite or necessary to be done in and about the
+premises, as fully to all intents and purposes as he might or could do in
+person, hereby, ratifying and confirming all that each of said
+attorneys-in-fact and agents, or his substitute or substitutes, may lawfully do
+or cause to be done by virtue hereof. 
+Pursuant to the
+requirements of the Securities Exchange Act of 1934, this report has been
+signed below by the following persons on behalf of the registrant in the
+capacities and on the dates indicated: 
+Signature 
+Title 
+Date 
+/s/ ABBAS MOHADDES 
+Director, President and Chief Executive Officer 
+June 21, 2007 
+Abbas Mohaddes 
+(principal executive officer) 
+/s/ JAMES S. MIELE 
+Chief Financial Officer 
+June 21, 2007 
+James S. Miele 
+(principal financial and accounting officer) 
+/s/ GREGORY A. MINER 
+Chairman of the Board 
+June 21, 2007 
+Gregory A. Miner 
+/s/ RICHARD CHAR 
+Director 
+June 21, 2007 
+Richard Char 
+/s/ KEVIN C. DALY 
+Director 
+June 21, 2007 
+Kevin C. Daly, Ph.D. 
+/s/ GARY HERNANDEZ 
+Director 
+June 21, 2007 
+Gary Hernandez 
+/s/ HARTMUT MARWITZ 
+Director 
+June 21, 2007 
+Hartmut Marwitz, Ph.D. 
+/s/ JOHN SEAZHOLTZ 
+Director 
+June 21, 2007 
+John Seazholtz 
+/s/ JOEL SLUTZKY 
+Director 
+June 21, 2007 
+Joel Slutzky 
+/s/ THOMAS L. THOMAS 
+Director 
+June 21, 2007 
+Thomas L. Thomas 
+/s/ PAUL E. WRIGHT 
+Director 
+June 21, 2007 
+Paul E. Wright 
+40 
+Iteris, Inc. 
+Index to Consolidated Financial Statements 
+Report of Independent
+Registered Public Accounting Firm 
+Consolidated Balance
+Sheets as of March 31, 2007 and 2006 
+Consolidated
+Statements of Operations for the years ended March 31, 2007, 2006, and
+2005 
+Consolidated
+Statements of Stockholders’ Equity and Comprehensive Income for the years
+ended March 31, 2007, 2006, and 2005 
+Consolidated
+Statements of Cash Flows for the years ended March 31, 2007, 2006, and
+2005 
+Notes to
+Consolidated Financial Statements 
+41 
+Report
+of Independent Registered Public Accounting Firm 
+To the Board of
+Directors 
+Iteris, Inc. 
+Anaheim, California 
+We
+have audited the consolidated balance sheets of Iteris, Inc. as of March 31,
+2007 and 2006, and the related consolidated statements of operations,
+stockholders’ equity and comprehensive income and cash flows for each of the
+three years in the period ended March 31, 2007. 
+Our audits also included the financial statement schedules of Iteris,
+Inc. listed in Item 15(a). These
+financial statements and financial statement schedules are the responsibility
+of the Company’s management. Our
+responsibility is to express an opinion on these financial statements and
+schedules based on our audits. 
+We
+conducted our audits in accordance with the standards of the Public Company
+Accounting Oversight Board (United States). 
+Those standards require that we plan and perform the audit to obtain
+reasonable assurance about whether the financial statements are free of
+material misstatement. An audit includes
+examining, on a test basis, evidence supporting the amounts and disclosures in
+the financial statements. An audit also
+includes assessing the accounting principles used and significant estimates
+made by management, as well as evaluating the overall financial statement
+presentation. We believe that our audits
+provide a reasonable basis for our opinion. 
+In our
+opinion, the consolidated financial statements referred to above present
+fairly, in all material respects, the financial position of Iteris, Inc. as of
+March 31, 2007 and 2006, and the results of its operations and its cash flows
+for each of the three years in the period ended March 31, 2007, in conformity
+with U.S. generally accepted accounting principles. Also, in our opinion, the related financial
+statement schedules, when considered in relation to the basic consolidated
+financial statements taken as a whole, present fairly in all material respects
+the information set forth therein. 
+As
+discussed in Note 1 to the consolidated financial statements, effective April
+1, 2006, the Company changed its method of accounting for stock-based compensation. 
+/s/ McGladrey & Pullen, LLP 
+Irvine, California 
+June 21, 2007 
+42 
+Iteris, Inc. 
+Consolidated Balance Sheets 
+(In thousands) 
+March 31, 
+2007 
+2006 
+Assets 
+Current assets: 
+Cash and cash
+equivalents 
+$ 
+35 
+$ 
+131 
+Trade accounts
+receivable, net of allowance for doubtful accounts of $664 and $429 at
+March 31, 2007 and 2006, respectively. 
+11,493 
+11,426 
+Costs and estimated
+earnings in excess of billings on uncompleted contracts 
+3,689 
+2,693 
+Deferred income taxes 
+494 
+790 
+Inventories, net of
+reserve for inventory obsolescence of $844 and $592 at March 31, 2007
+and 2006, respectively 
+6,379 
+2,814 
+Prepaid expenses and
+other current assets 
+385 
+368 
+Total current assets 
+22,475 
+18,222 
+Property and equipment: 
+Leasehold improvements 
+112 
+112 
+Equipment 
+6,830 
+6,638 
+Accumulated
+depreciation 
+(5,230 
+) 
+(4,967 
+) 
+1,712 
+1,783 
+Deferred income taxes 
+2,533 
+818 
+Intangible assets, net of accumulated amortization of $408 and $261
+at March 31, 2007 and 2006, respectively 
+404 
+551 
+Goodwill 
+27,774 
+27,774 
+Other assets 
+352 
+485 
+Total assets 
+$ 
+55,250 
+$ 
+49,633 
+See accompanying
+notes. 
+43 
+Iteris, Inc. 
+Consolidated Balance Sheets 
+(In thousands, except share and per
+share amounts) 
+March 31, 
+2007 
+2006 
+Liabilities and
+stockholders’ equity 
+Current liabilities: 
+Trade accounts payable 
+$ 
+3,542 
+$ 
+3,620 
+Accrued payroll and related expenses 
+3,527 
+3,481 
+Accrued liabilities 
+1,618 
+2,588 
+Revolving line of credit 
+4,015 
+2,662 
+Billings in excess of costs and estimated earnings
+on uncompleted contracts 
+847 
+893 
+Current portion of long-term debt 
+1,947 
+1,969 
+Total current
+liabilities 
+15,496 
+15,213 
+Non-current
+liabilities 
+163 
+177 
+Deferred
+compensation plan liability 
+730 
+820 
+Long-term debt 
+350 
+2,171 
+Convertible
+debentures, net 
+9,410 
+9,203 
+Commitments and
+contingencies 
+Redeemable
+common stock 
+Issued and outstanding shares — 1,219,445 at
+March 31, 2007 and 2006 
+3,414 
+3,414 
+Stockholders’
+equity: 
+Preferred stock: 
+Authorized shares — 2,000,000 
+Issued and outstanding — none 
+— 
+— 
+Common stock, $.10 par value: 
+Authorized shares — 50,000,000 
+Issued and outstanding shares — 30,600,717 at
+March 31, 2007 and 27,431,502 at March 31, 2006 
+3,060 
+2,743 
+Additional paid-in capital 
+130,425 
+126,664 
+Common stock held in trust — 310,510 shares at
+March 31, 2007 and 2006 
+(374 
+) 
+(374 
+) 
+Notes receivable from employees 
+(5 
+) 
+(49 
+) 
+Accumulated deficit 
+(107,438 
+) 
+(110,356 
+) 
+Accumulated other comprehensive income 
+19 
+7 
+Total
+stockholders’ equity 
+25,687 
+18,635 
+Total liabilities and
+stockholders’ equity 
+$ 
+55,250 
+$ 
+49,633 
+See accompanying notes. 
+44 
+Iteris, Inc. 
+Consolidated Statements of Operations 
+(In thousands, except per share amounts) 
+Year Ended March 31, 
+2007 
+2006 
+2005 
+Net sales and
+contract revenues: 
+Net sales 
+$ 
+36,248 
+$ 
+31,156 
+$ 
+29,062 
+Contract revenues 
+22,049 
+19,330 
+17,335 
+Total net sales
+and contract revenues 
+58,297 
+50,486 
+46,397 
+Costs of net
+sales and contract revenues: 
+Cost of net sales (a) 
+19,829 
+16,493 
+15,925 
+Cost of contract revenues (a) 
+14,460 
+12,600 
+13,789 
+Gross profit 
+24,008 
+21,393 
+16,683 
+Operating
+expenses: 
+Selling, general and administrative (a) 
+16,094 
+15,362 
+21,027 
+Research and development (a) 
+4,030 
+5,217 
+6,236 
+Amortization of intangible assets 
+147 
+147 
+114 
+Deferred compensation expense (benefit) 
+(91 
+) 
+48 
+(484 
+) 
+Disposal of fixed assets 
+— 
+— 
+422 
+Acquired in-process research and development 
+— 
+— 
+140 
+Total operating expenses 
+20,180 
+20,774 
+27,455 
+Operating income
+(loss) 
+3,828 
+619 
+(10,772 
+) 
+Non-operating
+income (expense): 
+Other income (expense), net 
+(653 
+) 
+35 
+1,054 
+Interest expense, net 
+(1,600 
+) 
+(1,459 
+) 
+(1,178 
+) 
+Income (loss)
+before income taxes and minority interest 
+1,575 
+(805 
+) 
+(10,896 
+) 
+Income tax
+benefit 
+1,343 
+885 
+94 
+Minority
+interest in earnings of subsidiary 
+— 
+— 
+(526 
+) 
+Net income
+(loss) 
+$ 
+2,918 
+$ 
+80 
+$ 
+(11,328 
+) 
+Earnings (loss)
+per share: 
+Basic 
+$ 
+0.10 
+$ 
+0.00 
+$ 
+(0.45 
+) 
+Diluted 
+$ 
+0.09 
+$ 
+0.00 
+$ 
+(0.45 
+) 
+Weighted average
+shares outstanding: 
+Basic 
+29,698 
+28,182 
+25,284 
+Diluted 
+33,348 
+32,737 
+25,284 
+(a) Includes stock-based compensation expense as follows: 
+Cost of net
+sales 
+$ 
+13 
+$ 
+27 
+$ 
+280 
+Cost of contract
+revenues 
+60 
+205 
+2,391 
+Selling, general
+and administrative expense 
+195 
+364 
+7,063 
+Research and
+development expense 
+20 
+129 
+2,043 
+Total
+stock-based compensation expense 
+$ 
+288 
+$ 
+725 
+$ 
+11,777 
+See accompanying notes . 
+45 
+Iteris, Inc. 
+Consolidated Statements of Stockholders’
+Equity and Comprehensive
+Income 
+(In thousands) 
+Common Stock 
+Shares Outstanding 
+Common 
+Notes 
+Accumulated 
+Total 
+Class A 
+Shares 
+Class B 
+Shares 
+Amount 
+Additional 
+Paid-In 
+Capital 
+Stock 
+Held in 
+Trust 
+Treasury 
+Stock 
+Receivable 
+From 
+Employees 
+Accumulated 
+Deficit 
+Other 
+Comprehensive 
+Income 
+Stockholder’s 
+Equity 
+(Deficit) 
+Comprehensive 
+Income 
+(Loss) 
+Balance at March 31,
+2004 
+20,477 
+928 
+$ 
+2,141 
+$ 
+95,937 
+$ 
+— 
+$ 
+(1 
+) 
+$ 
+(45 
+) 
+$ 
+(99,108 
+) 
+$ 
+— 
+$ 
+(1,076 
+) 
+Warrant exercises 
+402 
+— 
+40 
+344 
+— 
+— 
+— 
+— 
+— 
+384 
+Stock option
+exercises 
+25 
+— 
+2 
+49 
+— 
+— 
+— 
+— 
+— 
+51 
+Issuance of
+warrants in connection with convertible debentures 
+— 
+— 
+— 
+1,101 
+— 
+— 
+— 
+— 
+— 
+1,101 
+Conversion of
+Class B common stock 
+1,020 
+(928 
+) 
+9 
+(9 
+) 
+— 
+— 
+— 
+— 
+— 
+— 
+Convertible
+debenture conversion to common stock 
+69 
+— 
+7 
+205 
+— 
+— 
+— 
+— 
+— 
+212 
+Issuance of
+common stock in connection with merger of Iteris Subsidiary 
+4,787 
+— 
+479 
+14,722 
+— 
+— 
+— 
+— 
+— 
+15,201 
+Issuance of
+warrants 
+— 
+— 
+— 
+26 
+— 
+— 
+— 
+— 
+— 
+26 
+Assumption of
+Iteris subsidiary stock options and warrants 
+— 
+— 
+— 
+12,383 
+— 
+— 
+— 
+— 
+— 
+12,383 
+Common stock held
+in trust 
+310 
+— 
+31 
+343 
+(374 
+) 
+— 
+— 
+— 
+— 
+— 
+Stock-based
+compensation 
+— 
+— 
+— 
+508 
+— 
+— 
+— 
+— 
+— 
+508 
+Net loss 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+(11,328 
+) 
+— 
+(11,328 
+) 
+$ 
+(11,328 
+) 
+Balance at
+March 31, 2005 
+27,090 
+— 
+2,709 
+125,609 
+(374 
+) 
+(1 
+) 
+(45 
+) 
+(110,436 
+) 
+— 
+17,462 
+$ 
+(11,328 
+) 
+Warrant exercises 
+98 
+— 
+9 
+28 
+— 
+— 
+— 
+— 
+— 
+37 
+Stock option
+exercises 
+244 
+— 
+25 
+275 
+— 
+— 
+(4 
+) 
+— 
+— 
+296 
+Issuance of
+warrants 
+— 
+— 
+— 
+28 
+— 
+— 
+— 
+— 
+— 
+28 
+Stock-based
+compensation 
+— 
+— 
+— 
+725 
+— 
+— 
+— 
+— 
+— 
+725 
+Retirement of
+treasury stock 
+— 
+— 
+— 
+(1 
+) 
+— 
+1 
+— 
+— 
+— 
+— 
+Foreign currency
+translation 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+7 
+7 
+$ 
+7 
+Net income 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+80 
+— 
+80 
+80 
+Balance at
+March 31, 2006 
+27,432 
+— 
+2,743 
+126,664 
+(374 
+) 
+— 
+(49 
+) 
+(110,356 
+) 
+7 
+18,635 
+$ 
+87 
+Warrant exercises 
+1,706 
+— 
+170 
+2,265 
+— 
+— 
+— 
+— 
+— 
+2,435 
+Stock option
+exercises 
+1,374 
+— 
+138 
+982 
+— 
+— 
+— 
+— 
+— 
+1,120 
+Issuance of
+warrants 
+— 
+— 
+— 
+22 
+— 
+— 
+— 
+— 
+— 
+22 
+Stock-based
+compensation 
+— 
+— 
+— 
+288 
+— 
+— 
+— 
+— 
+— 
+288 
+Issuance of
+common stock in connection with legal settlement 
+89 
+— 
+9 
+204 
+— 
+— 
+— 
+— 
+— 
+213 
+Repayment of
+notes receivable from employees 
+— 
+— 
+— 
+— 
+— 
+— 
+44 
+— 
+— 
+44 
+Foreign currency
+translation 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+12 
+12 
+$ 
+12 
+Net income 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+2,918 
+— 
+2,918 
+2,918 
+Balance at
+March 31, 2007 
+30,601 
+— 
+$ 
+3,060 
+$ 
+130,425 
+$ 
+(374 
+) 
+$ 
+— 
+$ 
+(5 
+) 
+$ 
+(107,438 
+) 
+$ 
+19 
+$ 
+25,687 
+$ 
+2,930 
+See accompanying notes. 
+46 
+Iteris, Inc. 
+Consolidated Statements of Cash Flows 
+(In thousands) 
+Year Ended March 31, 
+2007 
+2006 
+2005 
+Operating
+activities 
+Net income
+(loss) 
+$ 
+2,918 
+$ 
+80 
+$ 
+(11,328 
+) 
+Adjustments to
+reconcile net income (loss) to net cash provided by (used in) operating
+activities: 
+Change in deferred tax assets 
+(1,419 
+) 
+(948 
+) 
+(200 
+) 
+Depreciation of property and equipment 
+559 
+684 
+787 
+Stock-based compensation 
+288 
+725 
+11,777 
+Amortization of deferred gain on sale-leaseback 
+(284 
+) 
+(284 
+) 
+(609 
+) 
+Issuance of common stock in connection with legal settlement 
+213 
+— 
+— 
+Amortization of debt discounts 
+207 
+207 
+184 
+Amortization of intangible assets 
+147 
+147 
+114 
+Amortization of deferred financing costs 
+137 
+138 
+121 
+Fair value of warrants issued for services 
+22 
+— 
+26 
+Minority interest in earnings of subsidiary 
+— 
+— 
+526 
+Loss on disposal of assets 
+— 
+— 
+422 
+Write-off of acquired in-process research and
+development 
+— 
+— 
+140 
+Changes in operating assets and liabilities: 
+Accounts receivable 
+(67 
+) 
+(2,560 
+) 
+(611 
+) 
+Net costs and estimated earnings in excess of
+billings 
+(1,042 
+) 
+(658 
+) 
+961 
+Inventories 
+(3,565 
+) 
+1,530 
+(746 
+) 
+Prepaid expenses and other assets 
+19 
+109 
+41 
+Accounts payable and accrued expenses 
+(182 
+) 
+1,048 
+(789 
+) 
+Deferred revenue 
+— 
+— 
+(226 
+) 
+Net cash
+provided by (used in) operating activities 
+(2,049 
+) 
+218 
+590 
+Investing
+activities 
+Purchases of
+property and equipment 
+(488 
+) 
+(1,258 
+) 
+(670 
+) 
+Notes receivable 
+— 
+— 
+125 
+Acquisition
+costs 
+— 
+— 
+(80 
+) 
+Net cash used in
+investing activities 
+(488 
+) 
+(1,258 
+) 
+(625 
+) 
+Financing
+activities 
+Proceeds from
+borrowings on lines of credit, net 
+1,353 
+1,717 
+845 
+Proceeds from
+long-term debt 
+— 
+— 
+5,000 
+Payments on
+long-term debt 
+(1,843 
+) 
+(1,314 
+) 
+(1,038 
+) 
+Credit facility
+commitment fees 
+(40 
+) 
+— 
+— 
+Checks drawn in
+excess of available bank balances 
+(628 
+) 
+389 
+268 
+Proceeds from
+stock option and warrant exercises 
+3,555 
+333 
+501 
+Proceeds from
+notes receivable from employees 
+44 
+— 
+— 
+Proceeds from
+issuance of convertible debentures 
+— 
+— 
+9,436 
+Purchase of
+Iteris subsidiary Series A preferred stock 
+— 
+— 
+(17,543 
+) 
+Net cash
+provided by (used in) financing activities 
+2,441 
+1,125 
+(2,531 
+) 
+Increase
+(decrease) in cash 
+(96 
+) 
+85 
+(2,566 
+) 
+Cash and cash
+equivalents at beginning of year 
+131 
+46 
+2,612 
+Cash and cash
+equivalents at end of year 
+$ 
+35 
+$ 
+131 
+$ 
+46 
+Supplemental
+cash flow information: 
+Cash paid
+(received) during the period: 
+Interest 
+$ 
+1,263 
+$ 
+1,095 
+$ 
+747 
+Income taxes 
+39 
+(2 
+) 
+624 
+Supplemental
+schedule of non-cash investing and financing activities: 
+Property and
+equipment financing 
+$ 
+— 
+$ 
+127 
+$ 
+— 
+Fair value of
+warrants issued in settlement of liabilities 
+— 
+28 
+— 
+Exercises of
+stock options via notes receivable from employees 
+— 
+4 
+— 
+Retirement of
+treasury stock 
+— 
+1 
+— 
+Increase in
+promissory note to landlord to settle lease obligation 
+— 
+— 
+432 
+Acquisition of
+minority interest of the Iteris subsidiary 
+Intangible assets 
+— 
+— 
+812 
+Deferred tax liabilities 
+— 
+— 
+360 
+Goodwill 
+— 
+— 
+17,887 
+Reduction of minority interest 
+— 
+— 
+1,253 
+Issuance of
+warrants in connection with Debenture and Warrant Purchase Agreement 
+— 
+— 
+1,101 
+Conversion of
+convertible debt to equity 
+— 
+— 
+250 
+See accompanying notes. 
+47 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements 
+March 31,
+2007 
+1. Description
+of Business and Summary of Significant Accounting Policies 
+Description of Business 
+Iteris, Inc.,
+formerly known as Iteris Holdings, Inc. (the “Company”), is a leading
+provider of outdoor machine vision systems and sensors that optimize the flow
+of traffic and enhance driver safety. Using proprietary software and
+Intelligent Transportation Systems (“ITS”) industry expertise, the Company
+provides video sensor systems, transportation management and traveler
+information systems and other engineering and consulting services to the ITS
+industry. The ITS industry is comprised of companies applying a variety of
+technologies to enable the safe and efficient movement of people and goods. The
+Company uses its outdoor image recognition software expertise to develop
+proprietary algorithms for video sensor systems that improve vehicle safety and
+the flow of traffic. Using its knowledge of the ITS industry, the Company
+designs and implements transportation management systems that help public
+agencies reduce traffic congestion and provide greater access to traveler
+information. On October 22, 2004, the Company completed the merger with
+its majority-owned subsidiary, Iteris, Inc. (the “Iteris Subsidiary”), and
+officially changed the Company’s corporate name from Iteris Holdings, Inc.
+to Iteris, Inc. (Note 3). The Company was originally incorporated in
+Delaware in 1987 as Odetics, Inc. and in September 2003 changed its
+name to Iteris Holdings, Inc. to reflect its focus on the ITS industry and
+its capital structure at that time. 
+Basis of Presentation 
+The
+accompanying consolidated financial statements include the accounts of the
+Company and its subsidiaries. All significant intercompany accounts and
+transactions have been eliminated in consolidation. 
+Use of Estimates 
+The
+preparation of consolidated financial statements in conformity with accounting
+principles generally accepted in the United States requires management to make
+certain estimates and assumptions that affect the reported amounts of assets
+and liabilities and disclosures of contingent assets and liabilities at the
+date of the financial statements, and reported amounts of revenues and expenses
+during the reporting period. Actual results could differ from those estimates.
+Significant estimates made in the preparation of the consolidated financial
+statements include the allowance for doubtful accounts, deferred tax assets,
+inventory and warranty reserves, costs to complete long-term contracts,
+overhead rates used in cost-plus contracts, contract reserves, the valuation of
+equity instruments and estimates of future cash flows used to assess the recoverability
+of long-lived assets and the realization of goodwill. 
+Reclassifications 
+Certain
+reclassifications have been made to the prior year financial statements to
+conform to the current year presentation. 
+Revenue
+Recognition 
+Product revenues
+and related costs of sales are recognized upon the transfer of title, which
+generally occurs upon shipment or, if required, upon acceptance by the
+customer, provided that the Company believes collectibility of the net sales
+amount is reasonably assured. Accordingly, at the date revenue is recognized,
+the significant uncertainties concerning the sale have been resolved. 
+Contract revenues
+are derived primarily from long-term contracts with governmental agencies.
+Contract revenues include costs incurred plus a portion of estimated fees or
+profits determined on the percentage of completion method of accounting based
+on the relationship of costs incurred to total estimated costs. Any anticipated
+losses on contracts are charged to earnings when identified. Changes in job performance
+and estimated profitability, including those arising from contract penalty
+provisions and final contract settlements, may result in revisions to costs and
+revenues and are recognized in the period in which the revisions are
+determined. Profit incentives are included in revenue when their realization is
+reasonably assured. 
+In addition to
+product and contract revenue, the Company derives revenue from technology
+access fees, the provision of specific non-recurring contract engineering
+services and royalties. Technology access fee revenues are recognized evenly
+over the period in which they are earned. Non-recurring contract engineering
+revenues are recognized in the period in which the related services are
+performed. Royalty revenues are recorded in the period in which the royalty is
+earned, based on unit 
+48 
+sales
+of the Company’s products. Technology access fee revenues, contract engineering
+revenues and royalty revenues are included in net sales in the accompanying
+consolidated statements of operations. 
+Revenues from
+follow-on service and support, for which the Company charges separately, are
+recorded in the period in which the services are performed. 
+Concentration of Credit Risk 
+Accounts
+receivable are derived from revenues earned from customers located throughout
+North America and Europe. The Company generally does not require collateral or
+other security from customers. Collectibility of receivable balances is
+estimated through review of invoices outstanding greater than a certain period
+of time and ongoing credit evaluations of customers’ financial condition.
+Reserves are maintained for potential credit losses, and such losses have
+historically been within management’s expectations. 
+At March 31,
+2007 and 2006, accounts receivable from governmental agencies and prime
+government contractors were approximately $5.2 million and $4.4 million,
+respectively. No customer or government agency had a receivable balance at
+March 31, 2007 or 2006 greater than 10% of our total net sales and contract
+revenues for the years ended March 31, 2007 and 2006. 
+Fair Values of Financial Instruments 
+The
+fair value of cash and cash equivalents, receivables, inventories, accounts
+payable and accrued expenses approximate carrying value because of the short
+period of time to maturity. The fair value of line of credit agreements and
+long-term debt approximate carrying value because the related rates of interest
+approximate current market rates. The fair value of convertible debentures
+approximates carrying value because the effective interest rate, taking into
+account recorded debt discounts, approximates current market rates. At
+March 31, 2005, the fair value of redeemable common stock approximated
+carrying value since these shares were not tradable in any public equity markets.
+At March 31, 2007 and 2006, the estimated fair value of the redeemable
+shares was $2.8 million and $3.2 million, respectively, based on the closing
+price of the Company’s common stock on that date. 
+Cash and Cash Equivalents 
+Cash and cash
+equivalents consist of cash and short-term investments with initial maturities
+of ninety days or less. 
+Inventories 
+Inventories
+are stated at the lower of cost or market. Cost is determined using the
+first-in, first-out method. 
+Property and Equipment 
+Property and equipment are recorded at cost and are
+depreciated over the estimated useful life ranging from three to eight
+years. Leasehold improvements are
+depreciated over the term of the related lease or the estimated useful life of
+the improvement, whichever is shorter. 
+Beginning April 1, 2006, the Company began depreciating property and
+equipment using the straight-line method of depreciation, which the Company
+believes more closely approximates the usage of the underlying assets, which
+generally provide value evenly througout the estimated life. Prior to this date, the Company used the
+double declining balance method of depreciation. As a result of this change in estimate,
+depreciation expense declined by $455,000 for the year ended March 31, 2007,
+resulting in a $0.02 per share impact on basic and diluted earnings per share. 
+Goodwill and Long-Lived Assets 
+In accordance with Statement of Financial Accounting
+Standards (“SFAS”) No. 142, Goodwill and Intangible
+Assets (“SFAS 142”), goodwill is tested for impairment on an annual
+basis in the Company’s fourth fiscal quarter or more frequently if indicators
+of impairment exist, of which none have been identified. The performance of the test involves a
+two-step process. The first step of the
+impairment test involves comparing the fair value of the Company’s reporting
+units with each respective reporting unit’s carrying amount, including
+goodwill. The Company determines the
+fair value of reporting units using the income approach. If the carrying amount of a reporting unit
+exceeds the reporting unit’s fair value, the second step of the goodwill
+impairment test is performed to determine the amount of any impairment
+loss. The second step of the goodwill 
+49 
+impairment
+test involves comparing the implied fair value of the reporting unit’s goodwill
+with the carrying amount of that goodwill. 
+The Company evaluates long-lived assets for impairment
+in accordance with SFAS No. 144, Accounting for the
+Impairment or Disposal of Long-Lived Assets , which requires
+impairment evaluation on long-lived assets used in operations when indicators
+of impairment are present. Reviews are
+performed to determine whether the carrying value of assets is impaired, based
+on a comparison to undiscounted expected future cash flows. If this comparison indicates that there is
+impairment, the impaired asset is written down to fair value, which is typically
+calculated using discounted expected future cash flows and a discount rate
+based upon the Company’s weighted average cost of capital adjusted for risks
+associated with the related operations. 
+Impairment is based on the excess of the carrying amount over the fair
+value of those assets. 
+Income Taxes 
+The
+Company utilizes the liability method of accounting for income taxes as set
+forth in SFAS No. 109, Accounting for Income
+Taxes (“SFAS 109”). Under the
+liability method, deferred taxes are determined based on the temporary
+differences between the financial statement and tax bases of assets and
+liabilities using enacted tax rates. A
+valuation allowance is recorded when it is more likely than not that all or a
+portion of the deferred tax assets will not be realized. See Note 6. 
+Stock-Based
+Compensation 
+Effective
+April 1, 2006, the Company adopted SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS 123R”), which replaced SFAS No.
+123, Accounting for Stock-Based Compensation 
+(“SFAS 123”), superceded Accounting Principles Board Opinion No. 25 (“APB 25”),
+and amended SFAS No. 95, Statement of Cash Flows . Prior to April 1, 2006, the Company followed
+the disclosure-only provisions of SFAS 123, as amended by SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure , and, accordingly, accounted for its stock-based
+compensation plans using the intrinsic value method under APB 25 and related
+interpretations. 
+SFAS
+123R requires all stock-based payments, including grants of employee stock options,
+to be recognized in the statement of operations as an expense, based on their
+grant date fair values with such fair values amortized over the requisite
+service period. The Company elected to
+use the modified prospective transition method for transition to SFAS
+123R. Under the modified prospective
+method, SFAS 123R applies to all awards granted or modified after the date of
+adoption. In addition, under the
+modified prospective method, compensation expense will be recognized for all
+stock-based compensation awards granted prior to but not yet vested as of April
+1, 2006, based on grant-date fair values estimated in accordance with the
+original provisions of SFAS 123. 
+Accordingly, prior period amounts presented herein have not been
+restated to reflect the adoption of SFAS 123R. 
+The fair value
+concepts were not changed significantly as a result of implementing SFAS 123R;
+however, in adopting SFAS 123R, companies must choose among alternative
+valuation models and amortization assumptions. After assessing alternative
+valuation models and amortization assumptions, the Company continued to use
+both the Black-Scholes-Merton (“BSM”) option-pricing formula and straight-line
+amortization of compensation expense over the requisite service period of stock
+option grants. The Company will
+reconsider use of this model if additional information becomes available in the
+future that indicates another model would be more appropriate, or if grants
+issued in future periods have characteristics that cannot be reasonably estimated
+using this model. SFAS 123 did not
+require the estimation of forfeitures in the calculation of stock compensation
+expense; however, SFAS 123R does require such estimation and upon adoption of
+SFAS 123R, the Company changed its methodology to include an estimate of
+forfeitures. 
+In addition, in accordance with SFAS 123R,
+SFAS 109 and EITF Topic D-32, Intraperiod
+Tax Allocation of the Tax Effect of Pretax Income from Continuing Operations ,
+the Company has elected to recognize excess income tax benefits from stock
+option exercises in additional paid-in capital only if an incremental income
+tax benefit would be realized after considering all other tax attributes
+presently available to the Company. The Company measures the tax benefit
+associated with excess tax deductions related to stock-based compensation
+expense by multiplying the excess tax deductions by the statutory tax rates. 
+As a result of
+implementing SFAS 123R, the Company recognized incremental stock-based
+compensation expense of $208,000 for the year ended March 31, 2007, which
+reduced income before taxes and net income by $208,000, and reduced basic and diluted
+earnings per share by $0.01 for the year ended March 31, 2007. The adoption of SFAS 123R had no effect on
+cash flows from operating activities because no tax benefits are realized 
+50 
+from
+stock option exercises. The adoption of SFAS 123R also had no effect on cash
+flows from financing activities because the Company did not realize any excess
+tax benefits from stock option exercises. 
+The following
+table illustrates the effect on net income (loss) and earnings (loss) per share
+for the years ended March 31, 2006 and 2005 as if the Company had applied the
+fair value recognition provisions of SFAS 123R to options granted under the
+Company’s stock option plans. For
+purposes of this pro forma disclosure, the fair value of the options was
+estimated using the BSM option-pricing formula and amortized on a straight-line
+basis to expense over the options’ vesting period: 
+Year Ended March 31, 
+2006 
+2005 
+(In thousands, except per share amounts) 
+Net income (loss) — as reported 
+$ 
+80 
+$ 
+(11,328 
+) 
+Add: Stock-based compensation expense included in
+net income (loss) — as reported 
+725 
+11,777 
+Deduct: Total stock-based compensation expense
+determined under fair value based method for all awards 
+(1,108 
+) 
+(12,806 
+) 
+Net income (loss) — pro forma 
+$ 
+(303 
+) 
+$ 
+(12,357 
+) 
+Basic and diluted earnings (loss) per share — as
+reported 
+$ 
+0.00 
+$ 
+(0.45 
+) 
+Basic and
+diluted loss per share — pro forma 
+$ 
+(0.01 
+) 
+$ 
+(0.49 
+) 
+Research
+and Development Expenditures 
+Research and development
+expenditures are charged to expense in the period incurred. 
+Shipping
+and Handling Costs 
+Shipping
+and handling costs are included as cost of sales in the period during which the
+products ship. 
+Sales Taxes 
+Sales taxes are presented on a net basis (excluded
+from net sales and contract revenues) in the consolidated statements of
+operations. 
+Advertising
+Expenses 
+Advertising
+costs are expensed in the period incurred and totaled $152,000, $185,000 and
+$112,000 in the years ended March 31, 2007, 2006 and 2005, respectively. 
+Warranty 
+The Company generally provides a one to three year warranty from the
+original invoice date on all products, materials and workmanship. Products sold to certain original equipment
+manufacturer (“OEM”) customers sometimes carry longer warranties. Defective
+products will be either repaired or replaced, generally at the Company’s
+option, upon meeting certain criteria. The Company accrues a provision for the
+estimated costs that may be incurred for product warranties relating to a
+product as a component of cost of sales at the time revenue for that product is
+recognized. The accrued warranty
+provision is included within accrued expenses on the accompanying consolidated
+balance sheets. 
+Repair
+and Maintenance Costs 
+The
+Company incurs repair and maintenance costs in the normal course of business.
+Should the activity result in a permanent improvement to one of the Company’s
+leased facilities, the cost is capitalized as a leasehold improvement and
+amortized over its useful life or the remainder of the lease period, whichever
+is shorter. Non-permanent repair and maintenance costs are charged to expense
+as incurred. 
+Comprehensive Income 
+The only component of accumulated other comprehensive
+income is foreign currency translation adjustments. 
+51 
+Recent
+Accounting Pronouncements 
+In July 2006, the Financial Accounting Standards Board
+(the “FASB”) issued FASB Interpretation No. 48, Accounting
+for Uncertainty in Income Taxes (“FIN 48”). FIN 48 clarifies the accounting and reporting
+for income taxes recognized in accordance with SFAS 109. This Interpretation prescribes a
+comprehensive model for the financial statement recognition, measurement,
+presentation and disclosure of uncertain tax positions taken or expected to be
+taken in income tax returns. The Company
+is currently evaluating the impact of FIN 48 and will adopt this Interpretation
+in the first quarter of its fiscal year ending March 31, 2008. 
+In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS 157”), which defines fair
+value, establishes a framework for measuring fair value, and expands disclosure
+about fair value measurements. SFAS 157 does not require any new fair value
+measurements; rather it specifies valuation methods to be applied when fair
+value measurements are required under existing or future accounting
+pronouncements. SFAS 157 is effective for fiscal years beginning after November
+15, 2007, and interim periods within those fiscal years. Early application of
+the statement is encouraged. Generally, this statement will be applied
+prospectively. The Company is currently evaluating the impact of SFAS 157 and
+expects to adopt SFAS 157 in the first quarter of its fiscal year ending March
+31, 2009. 
+In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities —
+Including an Amendment of FASB Statement No. 115 (“SFAS 159”). SFAS
+159 permits entities to choose to measure many financial instruments and
+certain other items at fair value. Unrealized gains and losses on items for
+which the fair value option has been elected will be recognized in earnings at
+each subsequent reporting date. SFAS 159 is effective for financial statements
+issued for fiscal years beginning after November 15, 2007. The Company is evaluating the impact that the
+adoption of SFAS 159 will have on its results of operations and financial
+condition and expects to adopt SFAS 159 in its fiscal year ending March 31,
+2009. 
+2. Supplementary Financial Information 
+Inventories 
+The
+following table presents details regarding the Company’s inventories: 
+March 31, 
+2007 
+2006 
+(In thousands) 
+Materials and
+supplies 
+$ 
+4,705 
+$ 
+2,258 
+Work in process 
+366 
+217 
+Finished goods 
+1,308 
+339 
+$ 
+6,379 
+$ 
+2,814 
+Goodwill and Intangible Assets 
+March 31, 2007 
+March 31, 2006 
+Gross 
+Carrying 
+Amount 
+Accumulated 
+Amortization 
+Gross 
+Carrying 
+Amount 
+Accumulated 
+Amortization 
+(In thousands) 
+Intangible
+assets subject to amortization: 
+Developed Technology 
+$ 
+495 
+$ 
+(280 
+) 
+$ 
+495 
+$ 
+(179 
+) 
+Patents 
+317 
+(128 
+) 
+317 
+(82 
+) 
+Total 
+$ 
+812 
+$ 
+(408 
+) 
+$ 
+812 
+$ 
+(261 
+) 
+Amortization expense for
+intangible assets subject to amortization was $147,000 for the years ended
+March 31, 2007 and 2006 and $114,000 for the year ended March 31, 2005.
+Future estimated amortization expense for the next five years is as follows: 
+Year Ending March 31: 
+(In thousands) 
+2008 
+$ 
+147 
+2009 
+147 
+2010 
+58 
+2011 
+46 
+2012 
+6 
+$ 
+404 
+At March 31, 2007,
+goodwill was comprised of $18.0 million associated with the October 2004
+merger of the Iteris Subsidiary (Note 3); $9.6 million associated with the
+acquisitions of the Rockwell International Transportation Systems Group, Meyer
+Mohaddes Associates and the Viggen Systems Consulting Group; and $200,000
+associated with the purchase of the assets of Mil-Lektron, a complementary
+product to the Company’s Vantage video detection business. 
+52 
+Warranty Reserve Activity 
+The following table presents
+activity in accrued warranty obligations: 
+Year Ended March 31, 
+2007 
+2006 
+2005 
+(In thousands) 
+Balance at
+beginning of year 
+$ 
+519 
+$ 
+326 
+$ 
+192 
+Additions charged to cost of sales 
+630 
+517 
+614 
+Warranty claims 
+(629 
+) 
+(324 
+) 
+(480 
+) 
+Balance at end of year 
+$ 
+520 
+$ 
+519 
+$ 
+326 
+Earnings (Loss) Per Share 
+The
+following table sets forth the computation of basic and diluted income (loss)
+per share: 
+Year Ended March 31, 
+2007 
+2006 
+2005 
+(In thousands, except per share amounts) 
+Numerator: 
+Net income (loss) 
+$ 
+2,918 
+$ 
+80 
+$ 
+(11,328 
+) 
+Denominator: 
+Weighted average common shares used in basic
+computation 
+29,698 
+28,182 
+25,284 
+Dilutive stock options 
+3,346 
+3,818 
+— 
+Dilutive warrants 
+304 
+737 
+— 
+Weighted average common shares used in dilutive
+computation 
+33,348 
+32,737 
+25,284 
+Earnings (loss)
+per share: 
+Basic 
+$ 
+0.10 
+$ 
+0.00 
+$ 
+(0.45 
+) 
+Diluted 
+$ 
+0.09 
+$ 
+0.00 
+$ 
+(0.45 
+) 
+The following shares were
+excluded from the computation of diluted earnings (loss) per share as their
+effect would have been anti-dilutive: 
+Year Ended March 31, 
+2007 
+2006 
+2005 
+(In thousands) 
+Stock options 
+582 
+470 
+4,560 
+Warrants 
+1,240 
+1,265 
+1,095 
+Convertible debentures 
+2,729 
+2,729 
+2,729 
+53 
+3. Merger
+of the Company and the Iteris Subsidiary 
+On May 28,
+2004 (the “Closing Date”), in order to simplify the Company’s capital structure
+and facilitate the merger of the Iteris Subsidiary into the Company, the
+Company completed the purchase of all of the outstanding shares of the
+Series A preferred stock of the Iteris Subsidiary (the “Series A
+preferred stock”), which were held by DaimlerChrysler Ventures GmbH (“DCV”) and
+Hockenheim Investment Pte. Ltd. (“Hockenheim”), in exchange for approximately
+$17.5 million in cash. In addition, the Company acquired all of the 547,893
+shares of common stock of the Iteris Subsidiary held by DCV in exchange for the
+issuance of 1,219,445 shares of the Company’s Class A common stock (now
+known as the Company’s common stock) which was valued at $3.4 million at the
+date of issuance. The fair value of the Company’s common stock issued in the
+transaction was based on the quoted market price of the Company’s stock on the
+OTC Bulletin Board averaged over a five-day period. The purchase and exchange
+of the shares were made pursuant to a Stock Purchase and Exchange Agreement
+dated March 31, 2004, by and among the Company, the Iteris Subsidiary, DCV
+and Hockenheim (the “Purchase and Exchange Agreement”). 
+Pursuant
+to the Purchase and Exchange Agreement, the Company purchased 3,124,913 shares
+of the Series A preferred stock of the Iteris Subsidiary from DCV and
+Hockenheim for a purchase price of $5.61 per share. The purchase price
+represented the stated redemption value of the Series A preferred stock.
+The purchase of the shares was financed primarily with a $10.1 million
+convertible debenture financing completed in May 2004 with a group of
+accredited investors, in addition to a $5.0 million senior credit facility
+arranged through a bank and $2.4 million in cash (Note 5). 
+On
+June 30, 2004, the Company and certain minority stockholders of the Iteris
+Subsidiary (including certain officers and directors) entered into an exchange
+agreement whereby an aggregate of 1,319,541 shares of common stock of the
+Iteris Subsidiary were exchanged for 2,639,082 shares of the Company’s newly
+issued common stock valued at $8.6 million at the date of issuance. The fair
+value of the Company’s stock issued in the transaction was based on the quoted
+market price of the Company’s common stock on the OTC Bulletin Board averaged
+over a five-day period. The effect of this exchange was to reduce the residual
+minority interest in the Iteris Subsidiary to 8.1%. 
+On
+October 22, 2004, the Iteris Subsidiary was merged into the Company. The
+remaining 8.1% minority interest in the Iteris Subsidiary (consisting of
+1,228,981 shares of common stock of the Iteris Subsidiary) was converted to
+2,457,962 shares of the Company’s common stock valued at $7.6 million at the
+merger date. Immediately following the merger, the Company converted all of its
+outstanding Class B common stock (921,917 shares) into 1,014,108 shares of
+its common stock (formerly designated as Class A common stock). The
+exchange ratio used in conversion was determined by the Company’s Board of
+Directors. The fair value of the Company’s common stock issued in the
+transaction was based on the quoted market price of the Company’s common stock
+on the OTC Bulletin Board averaged over a five-day period. In October 2004,
+the Company also amended its certificate of incorporation to (a) change
+the voting rights of its common stock from one-tenth to one vote per share,
+(b) remove the ability to issue any further shares of Class B common
+stock, and (c) rename its Class A common stock to common stock. As a
+result, the Company currently has only one class of common stock outstanding,
+the common stock. 
+In
+connection with the merger, the Company assumed all outstanding options and
+warrants to purchase shares of common stock of the Iteris Subsidiary that were
+outstanding immediately prior to the merger, whether vested or unvested,
+together with the Iteris Subsidiary’s 1998 Stock Incentive Plan. Each such
+option and warrant assumed by the Company shall continue to have, and be subject
+to, the same terms and conditions as were applicable immediately prior to the
+merger, provided that (A) such option or warrant shall be exercisable for
+that number of whole shares of the Company’s common stock equal to the product
+of the number of shares of the Company’s common stock that were issuable upon
+exercise of such assumed option or warrant immediately prior to the merger
+multiplied by two (2) (the “Exchange Ratio”) rounded down to the nearest
+whole number of shares and (B) the per share exercise price for the shares
+of the Company’s common stock issuable upon exercise of such assumed option or
+warrant is equal to the quotient determined by dividing the exercise price per
+share at which such option or warrant was exercisable immediately prior to the
+merger by the Exchange Ratio (rounded up to the nearest whole cent). As a
+result, options and warrants to purchase approximately 3.1 million shares
+and 327,000 shares, respectively, of common stock of the Iteris Subsidiary
+assumed in the merger became options and warrants to purchase approximately
+6.1 million and 654,000 shares, respectively, of common stock of the
+Company. The weighted-average exercise prices of the assumed options and
+warrants were $1.09 and $2.32, respectively. Stock-based compensation expense
+of $11.3 million was recorded in connection with the assumption and exchange of
+vested Iteris Subsidiary stock options for stock options immediately
+exercisable into the Company’s common stock based on the difference between the
+fair market value of the Company’s common stock on the October 22, 2004
+merger date and the exercise price of the modified stock option. Additionally,
+the Company recorded approximately $1.4 million in deferred compensation
+related to the assumption of 
+54 
+unvested
+stock options to purchase common stock of the Iteris Subsidiary. Deferred
+compensation was amortized to stock-based compensation expense as the options
+vested; and all such options were fully vested at March 31, 2007. The Company also recorded $1.1 million of
+goodwill and additional paid-in-capital in connection with the 654,000 vested
+warrants assumed in the merger and acquisition of the Iteris Subsidiary. The
+$1.1 million value was based on the difference between the fair market value of
+the Company’s common stock on the October 22, 2004 merger date and
+modified exercise price of the assumed warrant awards. 
+The excess of the purchase price over the
+proportionate amount of minority interest acquired was allocated to acquired
+intangible assets based on the estimated fair values with the residual
+allocated to goodwill. Accordingly, the Company recorded goodwill of $18.0
+million, which represents the excess of the purchase price over the fair value
+of the proportionate identifiable net assets acquired. The estimated fair value
+of the intangible assets was determined using the income method and discounting
+future expected returns. The estimated useful life for each of the acquired
+intangible assets is provided below: 
+Patents 
+7 years 
+Developed
+technology 
+5 years 
+The following
+table summarizes fair values of the assets acquired and liabilities assumed and
+the allocation of the purchase price at the date of acquisition (in thousands): 
+Acquisition costs: 
+Issuance of common stock 
+$ 
+18,617 
+Assumption of Iteris Subsidiary warrants 
+1,114 
+Purchase of Iteris Subsidiary Series A
+preferred stock 
+17,543 
+Acquisition costs 
+80 
+Total
+acquisition costs 
+$ 
+37,354 
+Purchase price allocation: 
+Fair value of
+41% of Iteris Subsidiary 
+Patents 
+$ 
+317 
+Developed technology 
+495 
+Acquired in-process research and development 
+140 
+Deferred tax liabilities 
+(360 
+) 
+Reduction of minority interest 
+18,794 
+Goodwill (not deductable for tax purposes) 
+17,968 
+Total purchase price
+allocation 
+$ 
+37,354 
+On
+October 22, 2004, in connection with the Company’s merger with the Iteris
+Subsidiary, the Chief Executive Officer of the Iteris Subsidiary was promoted
+to President and Chief Executive Officer of the Company, replacing
+Mr. Gregory Miner. This merger triggered certain obligations under the
+Company’s change-in-control agreement with Mr. Miner. Accordingly, the
+Company recorded approximately $807,000 in severance expense, which included
+$57,000 for related payroll taxes, as a charge to operations for the year ended
+March 31, 2005. The severance amount was paid to Mr. Miner in
+bi-weekly installments over 30 months, and the final payment was made in April
+2007. 
+55 
+4. Costs
+and Estimated Earnings on Uncompleted Contracts 
+Costs incurred, estimated
+earnings and billings on uncompleted long-term contracts are as follows: 
+March 31, 
+2007 
+2006 
+(In thousands) 
+Total estimated
+contract value 
+$ 
+74,794 
+$ 
+74,990 
+Costs incurred
+on uncompleted contracts 
+$ 
+20,688 
+$ 
+18,233 
+Estimated earnings 
+2,069 
+1,823 
+22,757 
+20,056 
+Less billings to date 
+(19,915 
+) 
+(18,256 
+) 
+$ 
+2,842 
+$ 
+1,800 
+Included in
+accompanying consolidated balance sheets: 
+Costs and estimated earnings in excess of billings
+on uncompleted contracts 
+$ 
+3,689 
+$ 
+2,693 
+Billings in excess of costs and estimated earnings
+on uncompleted contracts 
+(847 
+) 
+(893 
+) 
+$ 
+2,842 
+$ 
+1,800 
+Costs
+and estimated earnings in excess of billings at March 31, 2007 and 2006
+include $786,000 and $806,000, respectively, that were not billable as certain
+milestone objectives specified in the contracts had not been attained.
+Substantially all costs and estimated earnings in excess of billings at
+March 31, 2007 are expected to be billed and collected during the year
+ending March 31, 2008. 
+5. Revolving
+Line of Credit and Long-Term Debt 
+Revolving Line of Credit 
+On
+May 28, 2004, the Iteris Subsidiary entered into a line of credit
+agreement with its former bank, which provided for a maximum available credit
+line of $5.0 million. This line of credit was assumed by the Company in
+October 2004 and expired on October 31, 2006. 
+In October 2006,
+the Company replaced its former credit facility and entered into a new two-year
+credit facility with a different bank. 
+The new facility provides for combined line of credit and term note
+borrowings of up to $8.0 million. Under
+the new credit facility, the Company may borrow against its eligible accounts
+receivable and eligible inventory, as defined in the credit agreement. Line of credit interest on borrowed amounts
+is payable monthly at the current stated prime rate plus 1.25%. Additionally, the Company is obligated to pay
+an unused line fee of 0.25% per annum applied to the amount by which the
+maximum credit amount exceeds the average daily principal balance during the
+preceding month. The new credit facility requires $2,000 in monthly collateral
+management fees and includes an early termination fee equal to 2% of the total
+facility during the first year of the agreement and 1% of the total facility in
+the second year of the agreement. 
+Additionally, the Company paid a commitment fee of $40,000 in October
+2006 and is obligated to pay an additional $40,000 on the one-year anniversary
+of the facility. The new credit facility is secured by substantially all of the
+assets of the Company. 
+On March 31, 2007,
+the available credit under the credit facility was $8.0 million, of which $2.4
+million was unused. 
+56 
+Long-Term Debt 
+Long-term debt consists of the following: 
+March 31, 
+2007 
+2006 
+(In thousands) 
+Convertible
+debentures, net 
+$ 
+9,410 
+$ 
+9,203 
+Bank term note 
+1,573 
+2,708 
+Promissory note
+to landlord 
+646 
+1,292 
+Other 
+78 
+140 
+11,707 
+13,343 
+Less current
+portion 
+(1,947 
+) 
+(1,969 
+) 
+$ 
+9,760 
+$ 
+11,374 
+Convertible
+Debentures, Net. In order to finance the purchase of the
+Iteris Subsidiary Series A preferred stock (Note 3), the Company entered
+into a Debenture and Warrant Purchase Agreement dated May 19, 2004 (the “Debenture
+and Warrant Purchase Agreement”), with a group of accredited investors, which
+included certain officers of the Company, pursuant to which the Company sold
+and issued subordinated convertible debentures in the aggregate original
+principal amount of $10.1 million. In connection with the issuance of the
+convertible debentures, the Company issued detachable warrants to purchase an
+aggregate of 639,847 shares of its common stock (Note 9), the value of which
+was recorded as a debt discount against the face amount of the debentures on
+the date of issuance and is being amortized to interest expense over the term
+of the convertible debentures. 
+The
+debentures are due in full on May 19, 2009, provide for 6.0% annual
+interest, payable quarterly, and are convertible at the holder’s option into
+the Company’s common stock at an initial conversion price of $3.61 per share,
+subject to certain adjustments, including adjustments for dilutive issuances.
+From May 19, 2007, until May 18, 2008, the debentures may be redeemed
+by the Company, at its option, at 120% of the principal amount being redeemed;
+and from May 19, 2008, until the maturity date, the debentures may be
+redeemed at 110% of the principal amount being redeemed. During the year ended
+March 31, 2005, $250,000 of convertible debentures were converted into
+69,252 shares of common stock leaving $9.9 million of the originally issued
+convertible debentures outstanding at March 31, 2007 and 2006. 
+Bank Term
+Note. Concurrent with the Company’s issuance of the
+convertible debentures, the Iteris Subsidiary entered into a $5.0 million term
+note with a bank. This note was assumed by the Company in October 2004.
+The proceeds from the note were used to purchase the Series A preferred
+stock of the Iteris Subsidiary (Note 3). The note was due on May 27, 2008,
+and provided for monthly principal payments of approximately $104,000. Interest accrued at the current stated prime
+rate plus 0.25%. In October 2006, the
+term note was transferred to the Company’s new bank as part of the Company’s
+new $8.0 million credit facility. The new term note is also due on May 27, 2008
+and provides for monthly principal payments of approximately $104,000. Interest accrues under the new term note at
+the current stated prime rate plus 1.25%. 
+Amounts due under the term note reduce the Company’s ability to borrow
+against its eligible assets on its line of credit. 
+Both the new bank
+term note and the new line of credit are held by one bank under the same credit
+agreement and are secured by substantially all of the assets of the Company. 
+Promissory
+Note to Landlord. The Company has a $1.3 million unsecured
+promissory note payable to the landlord of its Anaheim headquarters. Under the terms of the note agreement,
+interest is payable quarterly and accrues at a rate of prime plus 2.0% (10.25%
+at March 31, 2007). In October 2006, January
+2007 and April 2007, the Company made the first three of four required equal
+quarterly principal payments of $323,000. 
+All outstanding accrued interest and principal are payable in full on
+July 1, 2007. 
+57 
+Scheduled aggregate maturities of long-term debt
+principal as of March 31, 2007 were as follows: 
+Year Ending March 31, 
+(In thousands) 
+2008 
+$ 
+1,947 
+2009 
+350 
+2010 
+9,850 
+12,147 
+Less:
+unamortized debt discount 
+(440 
+) 
+$ 
+11,707 
+6. Income Taxes 
+The reconciliation of the Company’s income tax benefit
+to taxes computed at U.S. federal statutory rates is as follows: 
+Year Ended March 31, 
+2007 
+2006 
+2005 
+(In thousands) 
+Income tax
+(benefit) provision at statutory rates 
+$ 
+536 
+$ 
+(284 
+) 
+$ 
+(3,705 
+) 
+State income
+taxes net of federal benefit 
+(147 
+) 
+(85 
+) 
+(72 
+) 
+Change in
+valuation allowance associated with federal deferred tax assets 
+(1,895 
+) 
+(892 
+) 
+(755 
+) 
+Compensation
+charges 
+— 
+222 
+3,692 
+Adjustment to
+prior year deferred taxes 
+— 
+— 
+229 
+Expiration of
+unused credits 
+— 
+— 
+266 
+AMT and foreign
+taxes 
+24 
+46 
+— 
+Other permanent
+differences 
+139 
+108 
+251 
+Income tax benefit 
+$ 
+(1,343 
+) 
+$ 
+(885 
+) 
+$ 
+(94 
+) 
+The components of deferred tax assets and liabilities
+are as follows: 
+March 31, 
+2007 
+2006 
+(In thousands) 
+Deferred tax
+assets: 
+Net operating losses 
+$ 
+18,806 
+$ 
+18,061 
+Property and equipment 
+— 
+623 
+Credit carry forwards 
+1,401 
+1,356 
+Deferred compensation and payroll 
+2,032 
+1,770 
+Bad debt allowances and other reserves 
+524 
+410 
+Acquired intangibles 
+67 
+— 
+Other, net 
+— 
+124 
+Total deferred
+tax assets 
+22,830 
+22,344 
+Valuation
+allowance 
+(19,543 
+) 
+(20,516 
+) 
+Net deferred tax
+assets 
+3,287 
+1,828 
+Deferred tax
+liabilities: 
+Other, Net 
+(135 
+) 
+— 
+Property and equipment 
+(125 
+) 
+— 
+Acquired intangibles 
+— 
+(220 
+) 
+Total deferred
+tax liabilities 
+(260 
+) 
+(220 
+) 
+Net deferred tax
+assets 
+$ 
+3,027 
+$ 
+1,608 
+Current portion
+of net deferred taxes 
+494 
+790 
+Long-term
+portion of net deferred taxes 
+2,533 
+818 
+Net deferred tax assets 
+$ 
+3,027 
+$ 
+1,608 
+58 
+The components of current and deferred federal and
+state income tax benefits and provisions are as follows: 
+Year Ended March 31, 
+2007 
+2006 
+2005 
+(In thousands) 
+Current income
+tax provision 
+Federal 
+$ 
+25 
+$ 
+9 
+$ 
+91 
+State 
+32 
+3 
+14 
+Foreign 
+24 
+46 
+— 
+Deferred income
+tax benefit 
+Federal 
+(1,170 
+) 
+(812 
+) 
+(75 
+) 
+State 
+(254 
+) 
+(131 
+) 
+(124 
+) 
+Net income tax benefit 
+$ 
+(1,343 
+) 
+$ 
+(885 
+) 
+$ 
+(94 
+) 
+At
+March 31, 2007, the Company had approximately $583,000 in federal general
+business credit carryforwards that begin to expire in 2008 and $818,000 in
+state general business credit carryforwards that can be carried forward
+indefinitely. The Company had $49.3 million of federal net operating loss
+carryforwards at March 31, 2007, that begin to expire in 2019 and $22.4
+million of state net operating loss carryforwards that begin to expire in 2008. 
+Prior
+to May 28, 2004, the Iteris Subsidiary was required to file a separate
+federal income tax return. On May 28, 2004, the Company acquired a greater
+than 80% ownership interest in the Iteris Subsidiary. From that date forward,
+income taxes are provided on a consolidated basis for federal income tax
+purposes. Due to changes in stock ownership, the prior year $49.8 million of
+federal net operating loss carryforwards and other federal tax attributes of
+the Company are subject to a Section 382 limitation estimated at
+approximately $2.9 million annually which can be utilized to offset federal
+consolidated taxable income. To the extent such limitation is not exceeded in a
+particular year, the excess limitation accumulates and adds to subsequent years’
+limitations. 
+At
+March 31, 2007, the Company recorded a valuation allowance against its net
+deferred tax assets of approximately $19 million for that portion of deferred
+tax assets that it is more likely than not will not be realized. In making such
+determination, a review of all available positive and negative evidence was
+considered, including scheduled reversal of deferred tax liabilities, potential
+carryback, projected future taxable income, tax planning strategies, and recent
+financial performance. Any future benefits recognized from the reduction of the
+valuation allowance will result in a reduction of income tax expense. 
+Unremitted
+earnings of the Company’s foreign subsidiary have been included in the
+consolidated financial statements without giving effect to the United States
+taxes that may be payable on distribution to the United States because it is
+not anticipated that such earnings will be remitted to the United States. If remitted, the additional United States
+taxes would not be material. 
+7. Commitments
+and Contingencies 
+Litigation 
+On June 29,
+2004, a supplier to Mariner Networks, Inc., a former subsidiary of the
+Company that was discontinued in the fiscal year ended March 31, 2002,
+filed a complaint in Orange County Superior Court against the Company alleging
+various breaches of written contract claims arising out of alleged purchase
+orders. The plaintiff in this lawsuit sought monetary damages aggregating approximately
+$850,000 plus attorney fees and related costs. 
+On July 20, 2006, the Company entered into a settlement agreement in
+connection with this matter. The dispute
+was settled in full for $688,000 payable as follows: (i) the Company issued 88,912 shares of the
+Company’s common stock on August 18, 2006 valued at $213,000 based on the
+closing sales price of the Company’s common stock on the date of issuance; (ii)
+the Company made a cash payment of $125,000 on October 20, 2006; and (iii) the
+Company is obligated to pay $350,000 in cash in equal monthly installments of
+$9,700 over three years beginning in November 2006. In connection with this settlement, the
+Company recorded a charge of $635,000, representing the fair value of the
+settlement, within other expense in the accompanying consolidated statement of
+operations for the year ended March 31, 2007. 
+In June 2004, the Company received $949,000 as
+part of a settlement between Rockwell International and the Michigan
+Department of Transportation, pursuant to which the Company was a third party
+beneficiary. This amount was recorded in other income in the consolidated
+statement of operations for the year ended March 31, 2005. 
+59 
+From
+time to time, the Company has been involved in litigation relating to claims
+arising out of its operations in the normal course of business. The Company
+currently is not a party to any legal proceedings, the adverse outcome of
+which, in management’s opinion, individually or in the aggregate, would have a
+material adverse effect on its consolidated results of operations, financial
+position or cash flows. 
+Furthermore, from time to
+time, the Company has experienced unforeseen developments in contingencies
+related to its former subsidiaries. For
+example, the Company has been the subject of a number of routine tax audits for
+time periods and jurisdictions related to the businesses of its former
+subsidiaries, some of which are still in process. Although the development and ultimate outcome
+of these and other unforeseen matters cannot be predicted with any certainty,
+management does not believe that the Company is presently involved in any
+matters related to its former subsidiaries that would have a material adverse
+effect on the Company’s consolidated results of operations, financial position
+or cash flows. 
+Operating
+Leases 
+The
+Company has lease commitments for facilities in various locations throughout
+the United States. Future minimum rental
+payments under these noncancelable operating leases at March 31, 2007 were as
+follows: 
+Fiscal Year Ending March 31, 
+(In thousands) 
+2008 
+$ 
+1,277 
+2009 
+1,398 
+2010 
+1,391 
+2011 
+1,348 
+2012 
+1,332 
+Thereafter 
+3,823 
+Total 
+$ 
+10,569 
+Rent expense totaled $2.2
+million, $1.9 million and $1.7 million, respectively, for the years ended March 31,
+2007, 2006 and 2005. 
+The
+Company has recorded on its consolidated balance sheet a deferred gain related
+to the May 2002 sale and leaseback of its headquarters in Anaheim,
+California. The deferred gain is being
+amortized over the term of the underlying lease, which terminates in September
+2007, and resulted in a realized gain of $284,000 in the fiscal years ended
+March 31, 2007 and 2006, and $609,000 in the fiscal year ended March 31,
+2005. The remaining deferred gain was
+$165,000 at March 31, 2007. 
+The
+Company subleases 10,000 square feet of space in its 94,000 square foot Anaheim,
+California facility at a monthly rate of $10,000 to MAXxess Systems, Inc.
+(“MAXxess”), a former subisidiary of the Company that was sold in September
+2003 and is currently owned by an investor group that includes one of the
+Company’s directors. During the fiscal
+year ended March 31, 2007, the Company wrote off amounts receivable from
+MAXxess aggregating $180,000 related primarily to this sublease due to MAXxess’
+inability to pay this balance. As a
+result of this write-off, the Company does not expect to recognize any future
+sublease income related to this sublease, which terminates in September 2007. 
+On May 25, 2007, the Company entered into an agreement to lease
+approximately 50,000 square feet of space in Santa Ana, California for a term
+of 88 months, beginning in September 2007. 
+This location will be the new location of the Company’s headquarters and
+principal operations. The monthly lease rate will be $102,000 during the first
+year of the lease, and will increase each year thereafter, up to a maximum of
+$120,000 during the last year of the lease. 
+The lease may be extended for a period of five years, at the option of
+the Company, at a lease rate to be based on the market lease rate for
+comparable property determined as of the commencement date of the extension
+period. Future lease commitments under
+this lease are included in the above table of lease commitments. 
+Inventory
+Purchase Commitments 
+At
+March 31, 2007, the Company had firm commitments to purchase inventory in
+the amount of $2.6 million during the first and second quarters of its fiscal
+year ending March 31, 2008. 
+60 
+Deferred
+Compensation Plan 
+In 1986, the
+Company adopted the Executive Deferral Plan (the “1986 Plan”) under which
+certain executives were able to defer a portion of their annual compensation
+into the 1986 Plan. All deferred amounts earned interest, generally with no
+guaranteed rate of return. 
+During the year
+ended March 31, 2003, the Iteris Subsidiary adopted the Deferred
+Compensation Plan for the sole purpose of transferring Iteris Subsidiary common
+stock and cash out of the 1986 Plan. All assets of the 1986 Plan were
+distributed prior to March 31, 2003. Certain of these assets, consisting
+of 133,333 shares of the Iteris Subsidiary’s common stock and $14,000 in cash,
+were transferred to the Deferred Compensation Plan during the year ended
+March 31, 2003. No compensation withholdings were deferred under the 1986
+Plan or the Deferred Compensation Plan in the years ended March 31, 2007,
+2006 and 2005. 
+During the year
+ended March 31, 2005, the Company assumed the Deferred Compensation Plan
+as part of the October 2004 merger and acquisition of the Iteris
+Subsidiary. In accordance with the merger (Note 3) the Company exchanged the
+original 133,333 shares of Iteris Subsidiary common stock held in the Deferred
+Compensation Plan and an additional 21,922 shares of the Iteris Subsidiary’s
+common stock subsequently purchased with deferred wages for 310,510 shares of the
+Company’s common stock. All shares of Iteris Subsidiary stock held in the plan
+were purchased with funds earned by the executives and deferred to the plan at
+the estimated fair value and the same price that was paid by outside investors
+at that time, or approximately $374,000. 
+At
+March 31, 2007, the Deferred Compensation Plan held 310,510 shares of the
+Company’s common stock and $15,000 in cash, which the Company has presented as
+an aggregated $730,000 deferred compensation plan liability in the accompanying
+consolidated balance sheet. Changes in the value of Company common stock held
+by the Deferred Compensation Plan are determined based on changes in the quoted
+market price of the Company’s common stock at the close of each reporting
+period and presented within operating expenses in the accompanying consolidated
+statements of operations. The original $374,000 cost basis of shares of Company
+common stock held in the Deferred Compensation Plan has been recorded as a
+contra-equity account in the accompanying consolidated financial
+statements. In May 2007, the Company’s
+former Chief Executive Officer, who departed in March 2007, elected to receive
+a distribution of fifty percent of his deferred compensation plan balance,
+representing 143,333 shares of the Company’s common stock and $8,000 in cash,
+on or before June 30, 2007, and his remaining deferred compensation plan
+balance of 143,333 shares of the Company’s common stock and $7,000 in cash on
+the one year anniversary of this election. 
+8. Redeemable
+Common Stock 
+As
+discussed in Note 3, the Company issued 1,219,445 shares of its Class A
+common stock (now known as common stock) (“Exchange Shares”) in connection with
+the merger of the Iteris Subsidiary into the Company. Beginning on
+November 28, 2005, DCV may require the Company to repurchase up to 50% of
+the Exchange Shares at a purchase price of $1.438 per share; and beginning on
+May 28, 2007, DCV may require the Company to repurchase up to 100% of the
+Exchange Shares at a purchase price of $1.438 per share. All such rights to
+require the repurchase of the Exchange Shares expire on September 28,
+2007. Because this right is outside the control of the Company, the Company has
+classified the $3.4 million value of the 1,219,445 shares as redeemable common
+stock on the accompanying March 31, 2007 and 2006 consolidated balance
+sheets. On February 1, 2005, DCV announced that its investment portfolio,
+which included its ownership in Iteris, Inc., was sold to European-based
+Cipio Partners for an undisclosed sum. All repurchase rights associated with
+the DCV shares inured to the benefit of Cipio Partners. 
+9. Stockholders’
+Equity 
+Preferred
+Stock 
+The
+Company’s certificate of incorporation provides for the issuance of up to
+2,000,000 shares of preferred stock. As of March 31, 2007 and 2006, there
+were no outstanding shares of preferred stock, and the Company does not have
+any plans to issue any shares of preferred stock. The Company’s Board of
+Directors is authorized to issue from time to time such authorized but unissued
+shares of preferred stock in one or more series and to fix or alter the
+designations, preferences, rights and any qualifications, limitations or
+restrictions of the shares of each such series, including the dividend,
+conversion, voting, redemption and liquidation rights. 
+61 
+Common
+Stock and Common Stock Warrants 
+On September 28,
+2006, the Company issued warrants to purchase an aggregate 246,250 shares of
+common stock at an exercise price of $3.25 with a five-year life to an existing
+shareholder in exchange for the early exercise of 1,250,000 outstanding
+warrants with an exercise price of $1.61. 
+The new warrants were immediately exercisable and are callable by the
+Company if the market price of the Company’s common stock trades for 20
+consecutive days at a price greater than or equal to two times the exercise
+price of the warrants. The fair value of
+the new warrants was $320,000 calculated using the Black-Scholes-Merton (“BSM”)
+option-pricing formula. The warrants
+were considered a cost of raising capital and were recorded in equity. 
+In connection with the
+issuance of the new warrants, the Company is party to a registration rights
+agreement that contains provisions under which the Company could be subjected
+to liquidated damages should it fail to maintain effective registration
+statements for the shares of common stock issuable upon exercise of the
+warrants. These warrants have been
+accounted for within equity in the consolidated balance sheet as of March 31,
+2007 in accordance with EITF 00-19 Accounting for Derivative
+Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own
+Stock , and, accordingly, no liabilities have been recorded in
+connection therewith. As of March 31,
+2007, no liquidated damages were payable under the provisions of the registration
+rights agreement associated with these warrants. 
+As discussed in Note 3, on October 22, 2004, the Iteris Subsidiary
+was merged into the Company. Also in October 2004, the Company amended its
+certificate of incorporation to (a) change the voting rights of its
+Class A common stock from one-tenth to one vote per share, (b) remove
+the ability to issue any further shares of Class B common stock, and
+(c) rename its Class A common stock to common stock. As a result, the
+Company currently has only one class of common stock outstanding, the common
+stock. Previously, the Company had two classes of common stock outstanding —
+the Class A common stock and the Class B common stock. 
+Subject to the rights
+specifically granted to holders of any then outstanding shares of the Company’s
+preferred stock, the Company’s common stockholders are entitled to any
+dividends that may be declared by the Board of Directors. Upon dissolution,
+liquidation or winding up, holders of common stock are entitled to share
+ratably in net assets after payment or provision for all liabilities and any
+preferential liquidation rights of preferred stock then outstanding. Common
+stockholders generally do not have preemptive or redemption rights, except for
+the Exchange Shares issued to DCV in exchange for shares of the Iteris
+Subsidiary (Notes 3 and 8). The rights, preferences and privileges of holders
+of common stock will be subject to those of the holders of any shares of common
+stock and preferred stock the Company may issue in the future. 
+Pursuant to the Debenture and Warrant Purchase
+Agreement discussed in Note 5, each individual investor also received two
+warrants to purchase shares of the Company’s common stock. For every dollar of
+debenture purchased, each investor received one warrant to purchase
+approximately 0.03235 shares of the Company’s common stock at an exercise price
+of $3.86 per share and a second warrant to purchase approximately 0.03100
+shares of the Company’s common stock at an exercise price of $4.03 per share.
+The exercise prices are subject to certain adjustments, including adjustments
+for dilutive issuances. The warrants to purchase 639,847 shares of common stock
+were immediately exercisable and expire on May 18, 2009. Debt discount
+costs related to the fair value of the warrants issued in connection with the
+convertible debentures were calculated based on the fair value of the warrants
+determined using the Black-Scholes valuation model and are being amortized to
+interest expense over the five-year term of the debentures. Significant
+valuation estimates used in the determination of the value of the warrants
+include an expected life of five years, no dividends, a risk-free interest rate
+of 4.5% and a stock volatility factor of 0.5. Unamortized debt discount
+aggregated $440,000 and $647,000 at March 31, 2007 and 2006, respectively,
+and is classified within convertible debentures, net on the accompanying
+consolidated balance sheets. 
+Also in connection with
+the Debenture and Warrant Purchase Agreement, the Company issued warrants to
+the investment bankers, as a commission, to purchase 34,036 shares of its
+common stock at an exercise price of $3.86 per share. The warrants were
+immediately exercisable and expire on May 18, 2009. The estimated fair
+value of these warrants of $40,000 was recorded as a deferred financing cost
+and is being amortized to interest expense over the five-year life of the
+debentures. Additionally, the Company incurred $621,000 in transaction costs
+associated with the debenture offering, which have also been capitalized as
+deferred financing costs and are being amortized to interest expense over the
+five-year term of the debentures. Unamortized deferred financing costs
+aggregated $293,000 and $430,000 at March 31, 2007 and 2006, respectively,
+and are classified within other assets on the accompanying consolidated balance
+sheets. 
+62 
+The following table summarizes information regarding
+outstanding warrants to purchase the Company’s common stock as of
+March 31, 2007: 
+Range of Exercise Prices 
+Warrants Outstanding 
+at March 31, 2007 
+Weighted Avg. 
+Remaining 
+Contractual Life 
+Weighted Avg. 
+Exercise Price 
+(In thousands, except per share amounts) 
+$1.42 to $1.95 
+127 
+1.12 
+$ 
+1.78 
+$2.45 to $3.25 
+286 
+3.70 
+$ 
+3.14 
+$3.61 to $4.03 
+674 
+2.13 
+$ 
+3.93 
+$5.00 to $5.26 
+230 
+2.66 
+$ 
+5.18 
+1,317 
+2.47 
+$ 
+3.77 
+All
+of the warrants were exercisable at March 31, 2007. Warrants to purchase an aggregate of 62,500
+shares of common stock at an exercise price of $1.95 per share and warrants to
+purchase an aggregate of 246,260 shares of common stock at an exercise
+price of $3.25 per share are callable by the Company if the market price of the
+Company’s common stock trades for 20 consecutive days at a price equal to or
+greater than two times the exercise price of the warrants. Warrants to purchase
+an aggregate of 75,000 shares of common stock at an exercise price of
+$5.00 per share are callable by the Company if the market price of the Company’s
+common stock trades for 20 consecutive days at a price equal to or greater
+than one and a half times the exercise price of the warrants. 
+Common
+stock reserved for future issuance at March 31, 2007: 
+(In thousands) 
+Issuable under
+stock options plans 
+5,827 
+Issuable upon
+the exercise of warrants 
+1,317 
+7,144 
+10. Associate
+Benefit Plans 
+Stock
+Option Plan 
+The Company’s 1997
+Stock Incentive Plan (the “Plan”) provides that options to purchase shares of
+the Company’s unissued common stock may be granted to directors, associates and
+consultants to the Company at exercise prices which are equal to or greater
+than the fair market value of the Company’s common stock on the date of
+grant. Options expire ten years after
+the date of grant or 90 days after termination of employment and generally vest
+ratably at the rate of 25% on each of the first four anniversaries of the grant
+date. New shares are issued to satisfy
+stock option exercises under the Plan. 
+As of March 31, 2007, options to purchase 1.6 million shares of the
+Company’s common stock were outstanding under the Plan. 
+In connection with
+the merger of the Company and the Iteris Subsidiary (Note 3), the Company
+assumed the 1998 Stock Incentive Plan of the Iteris Subsidiary (the “1998 Plan”)
+and all outstanding options granted thereunder. 
+As of March 31, 2007, options to purchase 3.6 million shares of the
+Company’s common stock were outstanding under the 1998 Plan. No further options may be granted under the
+1998 Plan. 
+Certain options
+granted under the Plan and the 1998 Plan (collectively, the “Plans”) provide
+for accelerated vesting of unvested options in the event of a change in control
+under certain circumstances. These
+change-in-control provisions meet the criteria of a performance condition under
+SFAS 123R. 
+As of March 31,
+2007, the Company had 711,000 outstanding stock options that were originally
+granted outside of the Plans and that were assumed by the Plan in connection
+with the merger of the Company and the Iteris Subsidiary (Note 3). 
+63 
+A summary of
+activity in the Plans for the year ended March 31, 2007 is as follows: 
+Options 
+Weighted 
+Average 
+Exercise 
+Price 
+Weighted 
+Average 
+Remaining 
+Life (In Years) 
+Aggregate 
+Intrinsic Value 
+(In thousands, except per share amounts) 
+Options outstanding at March 31, 2006 
+6,977 
+$ 
+1.42 
+4.0 
+Granted 
+272 
+$ 
+2.41 
+N/A 
+Exercised 
+(1,374 
+) 
+$ 
+0.81 
+N/A 
+Forfeited 
+(23 
+) 
+$ 
+2.86 
+N/A 
+Expired 
+(34 
+) 
+$ 
+2.13 
+N/A 
+Options outstanding at March 31, 2007 
+5,818 
+$ 
+1.60 
+3.4 
+$ 
+6,115 
+Vested and expected to vest at March 31, 2007 
+5,730 
+$ 
+1.59 
+3.4 
+$ 
+6,106 
+Options exercisable at March 31, 2007 
+5,324 
+$ 
+1.52 
+3.0 
+$ 
+6,001 
+Options
+exercisable at March 31, 2007 pursuant to a change-in-control 
+5,818 
+$ 
+1.60 
+3.4 
+$ 
+6,115 
+At March 31, 2007, there were 9,000 options available for grant under
+the Plan. 
+For the years ended March 31, 2007, 2006 and 2005, the Company received
+$1.1 million, $296,000 and $118,000, respectively, in cash from the exercise of
+stock options. 
+Stock-Based Compensation Expense 
+Total stock-based compensation expense for the years
+ended March 31, 2007, 2006 and 2005 was $288,000, $725,000 and $11.8 million,
+respectively. No income tax benefit was
+realized from activity in the Plans during the years ended March 31, 2007, 2006
+and 2005. 
+The fair value of each stock-based award is estimated
+on the grant date using the BSM option-pricing formula. 
+64 
+Expected volatility is based on the historical
+volatility of the Company’s stock price. The expected life of options granted
+subsequent to the adoption of SFAS 123R is derived based on the historical life
+of the Company’s options. The risk-free
+interest rate for periods within the expected life of the option is based on
+the U.S. Treasury interest rates in effect at the time of grant. The grant date
+fair value of options granted was estimated using the following
+weighted-average assumptions: 
+Years Ended March 31, 
+2007 
+2006 
+2005 
+Dividend yield 
+0.0 
+% 
+0.0 
+% 
+0.0 
+% 
+Expected life —
+years 
+7.0 
+7.0 
+7.0 
+Risk-free
+interest rate 
+4.7 
+% 
+5.5 
+% 
+4.5 
+% 
+Expected volatility of
+common stock 
+0.9 
+0.5 
+0.5 
+A summary of the grant date fair value and intrinsic value information
+is as follows: 
+Years Ended March 31, 
+2007 
+2006 
+2005 
+(In thousands, except per share amounts) 
+Weighted average
+grant date fair value per share of options granted 
+$ 
+1.92 
+$ 
+1.77 
+$ 
+1.83 
+Intrinsic value
+of options exercised 
+$ 
+2,288 
+$ 
+295 
+$ 
+20 
+Total fair value of
+options vested during the period 
+$ 
+638 
+$ 
+1,541 
+$ 
+1,206 
+At March 31, 2007, there was $855,000 of total unrecognized
+compensation expense related to unvested stock options. This expense is expected to be recognized
+over a weighted-average period of approximately 3.2 years. 
+Associate Incentive Programs 
+Under the terms of a Profit Sharing Plan, the Company
+contributes to a trust fund such amounts as are determined annually by the
+Board of Directors. No contributions were made during the years ended
+March 31, 2007, 2006 and 2005. 
+In May 1990, the Company adopted a 401(k) Plan
+as an amendment and replacement of the former Associate Stock Purchase Plan
+that was an additional feature of the Profit Sharing Plan. Under the
+401(k) Plan, eligible associates voluntarily contribute to the plan up to
+15% of their salary through payroll deductions. The Company matches 50% of
+contributions up to a stated limit. Under the provisions of the
+401(k) Plan, associates have thirteen investment choices, one of which is
+the purchase of Iteris, Inc. common stock at market price. Company matching
+contributions were approximately $480,000, $317,000, and $409,000 and for the
+years ended March 31, 2007, 2006, and 2005, respectively. 
+11. Disposal
+of Fixed Assets 
+After the merger of the Iteris Subsidiary into the
+Company on October 2004, the Company reviewed and determined certain
+corporate property and equipment would not provide value to its on-going
+operations. These assets primarily consisted of furniture and fixtures and
+computer equipment. Accordingly, the Company recorded a $422,000 loss on disposal
+of fixed assets in the year ended March 31, 2005. 
+12. Business
+Segment and Geographic Information 
+The Company currently operates in three reportable
+segments: Roadway Sensors, Automotive Sensors and Transportation Systems. The
+Roadway Sensors segment includes Vantage vehicle detection systems for traffic
+intersection control and certain highway traffic data collection
+applications. The Automotive Sensors segment is comprised of all activities
+related to AutoVue lane departure warning systems. The Transportation Systems
+segment includes transportation engineering and consulting services and the
+development of transportation management and traveler information systems for
+the ITS industry. The accounting policies of the reportable segments are the
+same as those described in the summary of significant accounting policies
+except that certain expenses, such as interest, amortization of certain
+intangibles and certain corporate expenses are not allocated to the segments.
+In addition, certain assets including cash and cash equivalents, deferred taxes
+and certain long-lived and intangible assets are not allocated to the segments.
+The reportable segments are each managed 
+65 
+separately because they
+manufacture and distribute distinct products or provide services with different
+processes. All segment revenues are derived from external customers. 
+Selected financial information for the Company’s
+reportable segments as of and for the years ended March 31, 2007, 2006 and
+2005 is as follows: 
+Roadway 
+Sensors 
+Automotive 
+Sensors 
+Transportation 
+Systems 
+Total 
+(In thousands) 
+Year
+Ended March 31, 2007 
+Product revenue
+from external customers 
+$ 
+27,261 
+$ 
+6,408 
+$ 
+— 
+$ 
+33,669 
+Service and
+other revenue from external customers 
+— 
+2,579 
+22,049 
+24,628 
+Stock-based
+compensation 
+37 
+54 
+78 
+169 
+Depreciation 
+82 
+138 
+126 
+346 
+Allocated
+goodwill 
+8,197 
+4,671 
+14,906 
+27,774 
+Segment income
+(loss) 
+6,035 
+(2,625 
+) 
+2,551 
+5,961 
+Year
+Ended March 31, 2006 
+Product revenue
+from external customers 
+$ 
+22,446 
+$ 
+5,865 
+$ 
+— 
+$ 
+28,311 
+Service and
+other revenue from external customers 
+— 
+2,845 
+19,330 
+22,175 
+Stock-based
+compensation 
+177 
+101 
+342 
+620 
+Depreciation 
+132 
+189 
+266 
+587 
+Allocated
+goodwill 
+8,197 
+4,671 
+14,906 
+27,774 
+Segment income
+(loss) 
+3,420 
+(2,476 
+) 
+1,842 
+2,786 
+Year
+Ended March 31, 2005 
+Product revenue
+from external customers 
+$ 
+21,920 
+$ 
+4,326 
+$ 
+— 
+$ 
+26,246 
+Service and
+other revenue from external customers 
+— 
+2,816 
+17,335 
+20,151 
+Stock-based
+compensation 
+2,492 
+1,505 
+3,971 
+7,968 
+Depreciation 
+117 
+116 
+415 
+648 
+Allocated
+goodwill 
+8,197 
+4,671 
+14,906 
+27,774 
+Segment income (loss) 
+1,140 
+(3,109 
+) 
+(2,440 
+) 
+(4,409 
+) 
+The Roadway Sensors segment had one customer with
+revenue representing 26.5% of total segment revenue for the year ended March
+31, 2007; one customer with revenue representing 25.9% of total segment revenue
+for the year ended March 31, 2006; and two customers with combined revenue
+representing 38.0% of total segment revenue for the year ended March 31,
+2005. The Automotive Sensors segment had three customers with combined revenue
+representing 64.2% of total segment revenue for the year ended March 31, 2007;
+two customers with combined revenue representing 70.7% of total segment revenue
+for the year ended March 31, 2006; and two customers with combined revenue
+representing 85.2% of total segment revenue for the year ended March 31,
+2005. The Transportation Systems segment had one customer with revenue representing
+13.3% of total segment revenue for the year ended March 31, 2007; and one
+customer with revenue representing 14.9% of total segment revenue for the year
+ended March 31, 2005. 
+In connection with the October 2004 merger of the
+Iteris Subsidiary into the Company (Note 3), goodwill of $8.0 million, $4.7
+million and $5.3 million was allocated to the Roadway Sensors, Automotive
+Sensors and Transportation Systems segments, respectively. This allocation was
+determined based on the respective fair value of each segment as calculated
+using the income approach. 
+66 
+The following reconciles segment income to
+consolidated income (loss) before income taxes and minority interest and
+segment assets to consolidated assets: 
+March 31, 
+2007 
+2006 
+2005 
+(In thousands) 
+Segment income
+(loss) 
+Total income
+(loss) for reportable segments 
+$ 
+5,961 
+$ 
+2,786 
+$ 
+(4,409 
+) 
+Unallocated
+amounts: 
+Corporate and other expenses 
+(2,077 
+) 
+(1,972 
+) 
+(6,171 
+) 
+Amortization of intangible assets 
+(147 
+) 
+(147 
+) 
+(114 
+) 
+Deferred compensation (expense) benefit 
+91 
+(48 
+) 
+484 
+Disposal of fixed assets 
+— 
+— 
+(422 
+) 
+Acquired in-process research and development 
+— 
+— 
+(140 
+) 
+Other income (expense), net 
+(653 
+) 
+35 
+1,054 
+Interest expense, net 
+(1,600 
+) 
+(1,459 
+) 
+(1,178 
+) 
+Income (loss) before income taxes and
+minority interest 
+$ 
+1,575 
+$ 
+(805 
+) 
+$ 
+(10,896 
+) 
+Assets 
+Total assets for
+reportable segments 
+$ 
+51,490 
+$ 
+47,520 
+$ 
+44,833 
+Unallocated
+assets 
+3,760 
+2,113 
+1,823 
+Total assets 
+$ 
+55,250 
+$ 
+49,633 
+$ 
+46,656 
+The Company’s
+revenues are generated and the Company’s assets are held substantially in the
+United States. 
+13. Quarterly
+Financial Data (Unaudited) 
+Net 
+Sales 
+Gross 
+Profit 
+Net 
+Income (Loss) 
+Basic 
+Earnings 
+(Loss) 
+per Share 
+Diluted 
+Earnings 
+(Loss) 
+per Share 
+(In thousands, except per share amounts) 
+June 30,
+2006 
+$ 
+13,816 
+$ 
+5,719 
+$ 
+279 
+$ 
+0.01 
+$ 
+0.01 
+September 30,
+2006 
+14,466 
+5,957 
+732 
+0.03 
+0.02 
+December 31,
+2006 
+14,488 
+5,676 
+310 
+0.01 
+0.01 
+March 31,
+2007 
+15,527 
+6,656 
+1,597 
+0.05 
+0.05 
+$ 
+58,297 
+$ 
+24,008 
+$ 
+2,918 
+$ 
+0.10 
+* 
+$ 
+0.09 
+* 
+June 30,
+2005 
+$ 
+12,079 
+$ 
+5,355 
+$ 
+(726 
+) 
+$ 
+(0.03 
+) 
+$ 
+(0.03 
+) 
+September 30,
+2005 
+12,715 
+5,442 
+(155 
+) 
+(0.01 
+) 
+(0.01 
+) 
+December 31,
+2005 
+12,183 
+4,981 
+136 
+0.00 
+0.00 
+March 31,
+2006 
+13,509 
+5,615 
+825 
+0.03 
+0.03 
+$ 
+50,486 
+$ 
+21,393 
+$ 
+80 
+$ 
+0.00 
+* 
+$ 
+0.00 
+* 
+* Annual per share
+amounts may not agree to the sum of the quarterly per share amounts due to
+differences between average shares outstanding during the periods. 
+67 
+Schedule II 
+Valuation and Qualifying Accounts (In thousands) 
+Description 
+Balance at 
+Beginning of 
+Period 
+Charged to 
+Costs and 
+Expenses 
+Charged to 
+Accounts 
+Balance at End 
+of Period 
+Year
+Ended March 31, 2007 
+Deducted from asset accounts: 
+Allowance for doubtful accounts 
+$ 
+429 
+$ 
+220 
+$ 
+15 
+$ 
+664 
+Reserve for inventory obsolescence 
+592 
+420 
+(168 
+) 
+844 
+Year
+Ended March 31, 2006 
+Deducted from asset accounts: 
+Allowance for doubtful accounts 
+$ 
+239 
+$ 
+275 
+$ 
+(85 
+) 
+$ 
+429 
+Reserve for inventory obsolescence 
+514 
+312 
+(234 
+) 
+592 
+Year
+Ended March 31, 2005 
+Deducted from asset accounts: 
+Allowance for doubtful accounts 
+$ 
+204 
+$ 
+37 
+$ 
+(2 
+) 
+$ 
+239 
+Reserve for
+inventory obsolescence 
+399 
+367 
+(252 
+) 
+514 
+68
\ No newline at end of file
diff --git a/raw/filings/0000350868/2006/0001104659-07-049160/filing_metadata.csv b/raw/filings/0000350868/2006/0001104659-07-049160/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..cac941b1ba776defc2840794da2c55a810e2b907
--- /dev/null
+++ b/raw/filings/0000350868/2006/0001104659-07-049160/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000350868,ITI,"ITERIS, INC.",10-K,2007-06-21,2007-03-31,2007-06-21T20:49:58.000Z,0001104659-07-049160,a07-16543_110k.htm,10-K,2070911,0,0,https://www.sec.gov/Archives/edgar/data/350868/000110465907049160/a07-16543_110k.htm,https://www.sec.gov/Archives/edgar/data/350868/000110465907049160/,2006,2006,1
diff --git a/raw/filings/0000350868/2006/0001104659-07-049160/item1.txt b/raw/filings/0000350868/2006/0001104659-07-049160/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..6f9b761004752f52bbb7e9a9c3591b729584d36f
--- /dev/null
+++ b/raw/filings/0000350868/2006/0001104659-07-049160/item1.txt
@@ -0,0 +1,272 @@
+ITEM 1. BUSINESS 
+Overview 
+Iteris, Inc.,
+formerly known as Iteris Holdings, Inc., is a leading provider of outdoor
+machine vision systems and sensors that optimize the flow of traffic and
+enhance driver safety. Using proprietary software and Intelligent
+Transportation Systems (“ITS”) industry expertise, we provide video sensor systems,
+transportation management and traveler information systems and other
+engineering and consulting services to the ITS industry. The ITS industry is
+comprised of companies applying a variety of technologies to enable the safe
+and efficient movement of people and goods. We use our outdoor image
+recognition software expertise to develop proprietary algorithms for video
+sensor systems that improve vehicle safety and the flow of traffic. Using our
+knowledge of the ITS industry, we design and implement transportation
+management systems that help public agencies reduce traffic congestion and
+provide greater access to traveler information. 
+We
+were originally incorporated in Delaware in 1987 as Odetics, Inc. and in
+September 2003 changed our name to Iteris Holdings, Inc. to reflect
+our focus on the ITS industry and our capital structure at that time. On
+October 22, 2004, we completed a merger with our majority-owned
+subsidiary, Iteris, Inc. (the “Iteris Subsidiary”), and officially changed
+our corporate name from Iteris Holdings, Inc. to Iteris, Inc. 
+Our proprietary image recognition systems include Vantage and AutoVue.
+Vantage is a video vehicle detection system that detects the presence of
+vehicles on roadways. Vantage systems are used at signalized intersections to
+enable a more efficient allocation of green signal time and are also used for
+incident detection and highway traffic data collection applications. AutoVue
+Lane Departure Warning (“LDW”) systems consist of a small windshield mounted
+sensor that uses proprietary software to detect and warn drivers of unintended
+lane departures. To date, we and our strategic partner have sold approximately
+83,000 production AutoVue LDW systems for use on car and truck platforms in the
+North American and European markets. We believe that our AutoVue LDW technology
+is a broad sensor platform that, through additional software development, may
+be expanded to incorporate additional safety and convenience features. 
+Our transportation management systems business includes transportation
+engineering and consulting services focused on the planning, design,
+development and implementation of software-based systems that integrate
+sensors, video surveillance, computers and advanced communications equipment to
+enable public agencies to monitor, control and direct traffic flow, assist in
+the quick dispatch of emergency crews and distribute real-time information
+about traffic conditions. Our services include planning, design and
+implementation of surface transportation infrastructure systems. We perform analysis and study goods movement,
+commercial vehicle operations, travel demand forecasting and systems
+engineering, and identify mitigation measures to reduce traffic
+congestion. These services and systems
+are primarily sold to local, state and national transportation agencies in the
+United States. Our transportation
+management systems business is largely dependent upon governmental 
+3 
+funding and budgetary issues. The Federal Highway Bill that was passed in
+August 2005 provided for a significant increase in transportation funding over
+the following six years. We believe the
+recent expansion of our transportation management systems business was due in
+part to the passage of the Federal Highway Bill, combined with the expansion of
+transportation funds at state and local agencies throughout the country. 
+We currently
+operate in three reportable segments: Roadway Sensors, Automotive Sensors and
+Transportation Systems. The Roadway Sensors segment includes our Vantage
+vehicle detection systems for traffic intersection control, incident detection
+and certain highway traffic data collection applications. The Automotive Sensors segment is comprised
+of all activities related to our AutoVue LDW systems for vehicle safety. The
+Transportation Systems segment includes transportation engineering and
+consulting services and the development of transportation management and
+traveler information systems for the ITS industry. See Note 12 to the accompanying consolidated
+financial statements for further discussion of our operating segments. 
+Sales, Marketing and Principal Customers 
+We
+sell our Vantage vehicle detection systems through indirect sales channels
+comprised of independent dealers in the United States and Canada who sell
+integrated systems and related products to the traffic management market, as
+well as directly to the traffic management market using a combination of our
+own sales personnel and an outside sales organization. Our independent dealers
+are primarily responsible for sales, installation and support of Vantage
+systems. These dealers maintain an inventory of demonstration traffic products
+from various manufacturers including our Vantage vehicle detection systems and
+sell directly to government agencies and installation contractors. These
+dealers often have long-term arrangements with the government agencies in their
+territory for the supply of various products for the construction and
+renovation of traffic intersections. We hold technical training classes for
+dealers and end users and maintain a full-time staff of customer support
+technicians to provide technical assistance when needed. 
+Our marketing strategy for AutoVue is to establish it as the leading
+platform for in-vehicle video sensing for heavy trucks and passenger cars. We sell AutoVue LDW systems directly to heavy
+truck manufacturers and to U.S. truck fleets, and our AutoVue LDW system is
+currently offered as an option on certain heavy trucks, including
+Mercedes-Benz, MAN, Iveco, DAF, Scania, Freightliner, International and FUSO,
+as well as Neoplan and MAN luxury bus and coach lines. We market the licensing
+of our LDW technology to manufacturers of passenger automobiles through an
+exclusive strategic relationship with Valeo Schalter and Sensuren GmbH (“Valeo”),
+an independent automotive supplier. In connection with this marketing effort,
+we provide specific contract engineering services, technical marketing and
+sales support to Valeo, which to date has enabled the launch of our LDW
+technology on three Infiniti car platforms, the FX, M and Q, where our LDW
+system is offered as part of the technology option package. We plan to continue
+to provide technical marketing and sales support to Valeo in our efforts to win
+new original equipment manufacturer (“OEM”) customers for the passenger car
+market as well as contract engineering services related to the possible launch
+of new platforms that include our AutoVue LDW system. 
+We market and sell our transportation management systems and traveler
+information services directly to government agencies pursuant to negotiated
+contracts that involve competitive bidding and specific qualification
+requirements. Most of our contracts with federal, state and municipal customers
+provide for cancellation or renegotiation at the option of the customer upon
+reasonable notice and fees paid for modification. We use selected members of
+our engineering team divided on a regional basis to serve in sales and business
+development functions. We do not engage in sales of transportation management
+systems and traveler information services outside of the U.S. Sales of our
+transportation management systems contracts generally involve long lead times
+and require extensive specification development, evaluation and price
+negotiations. 
+Our largest
+customer accounted for 12.4% of total net sales and contract revenues in the
+fiscal year ended March 31, 2007 (“Fiscal 2007”). 
+Manufacturing and Materials 
+We use contract manufacturers to build subassemblies that are used in
+our Vantage products. Additionally, we procure certain components from
+qualified suppliers, both globally and locally, and use multi-sourcing
+strategies when technically and economically feasible to mitigate supply risk.
+These subassemblies and components are delivered to our Anaheim facility where
+they go through final assembly and testing prior to shipment to our customers.
+Our manufacturing activities are conducted in approximately 8,000 square feet
+of space at our Anaheim facility. Production volume at our subcontractors is
+based upon quarterly forecasts that we adjust on a monthly basis to control
+inventory. For sales of AutoVue LDW systems to the truck market, we subcontract
+the manufacture of our AutoVue LDW systems to two manufacturers, and our
+internal processes are limited primarily to testing and final verification. For
+AutoVue LDW sales to the passenger car market, we 
+4 
+anticipate that all manufacturing will be done by
+Valeo; however, we plan to continue to provide engineering support to Valeo. We
+currently do not manufacture any of the hardware used in the transportation
+management and traveler information systems that we design and implement. Our
+production facility is currently ISO 9001 certified. 
+Customer
+Support and Services 
+We provide
+warranty service and support for our Vantage and AutoVue products, as well as
+follow-up service and support for which we charge separately. Service revenue
+accounted for less than 1.0% of total net sales and contract revenues for
+Fiscal 2007. We believe customer support is a key competitive factor. 
+Backlog 
+Our backlog of unfulfilled firm orders was approximately $25.7 million
+as of March 31, 2007, which was comprised of $3.5 million related to
+Roadway Sensors, $2.1 million related to Automotive Sensors and $20.1 million
+related to Transportation Systems. Substantially all of the backlog for Roadway
+Sensors and Automotive Sensors is expected to be recognized as revenue in the
+fiscal year ending March 31, 2008 (“Fiscal 2008”), while approximately
+75.0% of Transportation Systems backlog is expected to be recognized as revenue
+in Fiscal 2008. At March 31, 2006, we had backlog of approximately $20.3
+million, which was comprised of $1.5 million related to Roadway Sensors, $3.0
+million related to Automotive Sensors and $15.8 million related to
+Transportation Systems. All backlog as of March 31, 2006 for Roadway Sensors
+and Automotive Sensors was recognized as revenue in Fiscal 2007 while 58.9% of
+March 31, 2006 backlog for Transportation Systems was recognized as revenue in
+Fiscal 2007. Pursuant to the customary terms of our agreements with government
+contractors and other customers, customers can generally cancel or
+reschedule orders with little or no penalties. Lead times for the release
+of purchase orders often depend upon the scheduling and forecasting practices
+of our individual customers, which also can affect the timing of the conversion
+of our backlog into revenues. For these reasons, among others, our backlog at a
+particular date may not be indicative of our future revenues. 
+Product Development 
+Most of our development activities are conducted at our principal
+facilities in Anaheim, California. Our company-sponsored research and
+development costs and expenses were approximately $4.0 million for Fiscal 2007,
+$5.2 million for the fiscal year ended March 31, 2006 (“Fiscal 2006”), and
+$6.2 million for the fiscal year ended March 31, 2005 (“Fiscal 2005”). We
+expect to continue to pursue significant product development programs and incur
+significant research and development expenditures. 
+Competition 
+We generally face significant competition in each of our target
+markets. Increased competition may result in price reductions, reduced gross
+margins and loss of market share, any of which could have a material adverse
+effect on our business, financial condition and results of operations. We
+believe that AutoVue is the only established commercially-available lane
+departure warning system used in the U.S. and in Europe in the heavy truck
+market. Potential competitors of AutoVue include Delphi Automotive Systems
+Corporation, NEC Corporation and Hitachi Ltd. in Japan and Robert Bosch GmbH in
+Europe, as well as Siemens, Continental Tavis, Visteon and Cognex, which could
+be currently developing video sensor technologies for the vehicle industry that
+could be used for lane departure warning systems. In the market for our Vantage
+vehicle detection systems, we compete with manufacturers of other above ground
+video camera detection systems such as Econolite Control Products, Inc.,
+Traficon, N.V., Quixote, and other non-intrusive detection devices including
+microwave, infrared, ultrasonic and magnetic detectors, as well as
+manufacturers and installers of in-pavement inductive loop products. 
+The transportation management and traveler information systems market
+is highly fragmented and is subject to evolving national and regional quality
+and safety standards. Our competitors vary in number, scope and breadth of the
+products and services they offer. Our competitors in advanced transportation
+management and traveler information systems include national corporations such
+as Transcore, Siemens, Telvent Farradyne, Kimley-Horn and Associates, Inc.
+and Delcan. Our competitors in transportation engineering, planning and design
+include major firms such as Parsons Brinkerhoff, Inc., URS, HNTB and
+Parsons Transportation Group, Inc., as well as many smaller regional
+engineering firms. 
+In general, the markets for the products and services we offer are
+highly competitive and are characterized by rapidly changing technology and
+evolving standards. Many of our current and prospective competitors have longer
+operating histories, greater name recognition, access to larger customer bases
+and significantly greater financial, technical, manufacturing, distribution and
+marketing resources than us. As a result, they may be able to adapt more
+quickly to new or emerging standards or technologies or to devote greater
+resources to the promotion and sale of their products. It is also possible that
+new competitors or alliances among competitors could emerge and rapidly acquire
+significant market share. We believe that our ability to compete effectively in
+our target markets will depend on a number of factors, including the success
+and timing of our new product development, the compatibility of our products
+with a broad range of computing systems, product quality and 
+5 
+performance, reliability, functionality, price, and
+service and technical support. Our failure to provide services and develop and
+market products that compete successfully with those of other suppliers and
+consultants in our target markets would have a material adverse effect on our
+business, financial condition and results of operations. 
+Intellectual Property and Proprietary
+Rights 
+Our ability to compete effectively depends in part on our ability to
+develop and maintain the proprietary aspects of our technology. Our policy is
+to obtain appropriate proprietary rights protection for any potentially
+significant new technology acquired or developed by us. We currently hold ten
+U.S. patents, which expire commencing in 2012, and have six U.S.
+patent applications pending relating to our outdoor image processing techniques
+used in our AutoVue systems. Nine of our patents relate specifically to our
+AutoVue technology and provide a basis for enhanced functionality for rain
+sensing and improved performance. We believe that our other patents, while
+important for our technology platforms, are less critical to our near term
+product strategy. We cannot assure you that any new patents will be granted
+pursuant to any outstanding or subsequent applications. 
+In addition to patent laws, we rely on copyright and trade secret laws
+to protect our proprietary rights. We attempt to protect our trade secrets and
+other proprietary information through agreements with customers and suppliers,
+proprietary information agreements with our employees and consultants, and
+other similar measures. We do not have any material licenses or trademarks
+other than those relating to product names. We cannot be certain that we will
+be successful in protecting our proprietary rights. While we believe our
+patents, patent applications, software and other proprietary know-how have
+value, changing technology makes our future success dependent principally upon
+our employees’ technical competence and creative skills for continuing innovation. 
+Litigation may be necessary in the future to enforce our proprietary
+rights, to determine the validity and scope of the proprietary rights of
+others, or to defend us against claims of infringement or invalidity by others.
+An adverse outcome in such litigation or similar proceedings could subject us
+to significant liabilities to third parties, require disputed rights to be
+licensed from others or require us to cease marketing or using certain
+products, any of which could have a material adverse effect on our business,
+financial condition and results of operations. In addition, the cost of
+addressing any intellectual property litigation claim, both in legal fees and
+expenses, as well as from the diversion of management’s resources, regardless
+of whether the claim is valid, could be significant and could have a material
+adverse effect on our business, financial condition and results of operations. 
+Employees 
+We refer to our employees as associates. As of June 5, 2007, we
+employed an aggregate of 237 associates, including 57 associates in general
+management, administration and finance; 31 associates in sales and marketing;
+113 associates in engineering and product development; 25 associates in
+operations, manufacturing and quality; and 11 associates in customer service.
+None of our associates are represented by a labor union, and we have never
+experienced a work stoppage. 
+Government Regulation 
+Our manufacturing operations are subject to various federal, state and
+local laws and regulations, including those restricting the discharge of
+materials into the environment. We are not involved in any pending or, to our
+knowledge, threatened governmental proceedings, which would require curtailment
+of our operations because of such laws and regulations. We continue to expend
+funds in connection with our compliance with applicable environmental
+regulations. These expenditures have not, however, been significant in the
+past, and we do not expect any significant expenditure in the near future.
+Currently, compliance with foreign laws has not had a material impact on our
+business and is not expected to have a material impact in the near future. 
+6
\ No newline at end of file
diff --git a/raw/filings/0000350868/2006/0001104659-07-049160/item13.txt b/raw/filings/0000350868/2006/0001104659-07-049160/item13.txt
new file mode 100644
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--- /dev/null
+++ b/raw/filings/0000350868/2006/0001104659-07-049160/item13.txt
@@ -0,0 +1,6 @@
+ITEM 13. CERTAIN
+RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+The information
+under the captions “Corporate Governance – Director Independence” and “Certain
+Transactions,” appearing in our proxy statement for the 2007 Annual Meeting of
+Stockholders, is incorporated herein by reference.
\ No newline at end of file
diff --git a/raw/filings/0000350868/2006/0001104659-07-049160/item9a.txt b/raw/filings/0000350868/2006/0001104659-07-049160/item9a.txt
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index 0000000000000000000000000000000000000000..df01c3f50d092ca08547c47ca3c23366a7a10a04
--- /dev/null
+++ b/raw/filings/0000350868/2006/0001104659-07-049160/item9a.txt
@@ -0,0 +1,35 @@
+ITEM 9A. CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Controls and
+Procedures 
+As of the end of
+the period covered by this report, we carried out an evaluation, under the
+supervision and with the participation of our management, including our Chief
+Executive Officer and our Chief Financial Officer, of the effectiveness of the
+design and operation of our disclosure controls and procedures, as such term is
+defined in Exchange Act Rules 13a-15(e) and 15d-15(e). Based upon that
+evaluation, the Chief Executive Officer and Chief Financial Officer concluded
+that our disclosure controls and procedures are effective to ensure that
+information required to be disclosed by us in the reports that we file or
+submit under the Exchange Act is recorded, processed, summarized and reported
+within the time periods specified in the Securities and Exchange Commission’s
+rules and forms and are effective in ensuring that information required to be
+disclosed by us in the reports that we file or submit under the Exchange Act is
+accumulated and communicated to our management, including our Chief Executive
+Officer and Chief Financial Officer, as appropriate, to allow timely decisions
+regarding required disclosure. In designing and evaluating the disclosure
+controls and procedures, our management recognized that any controls and
+procedures, no matter how well designed and operated, can provide only
+reasonable assurance of achieving the desired control objectives. Our
+management necessarily applied its judgment in evaluating the cost-benefit
+relationship of such controls and procedures. 
+Changes in Internal Controls 
+During the most recent
+completed fiscal quarter covered by this report, there has been no change in
+our internal controls over financial reporting (as defined in Rules 13a-15(f) and
+15d-15(f) under the Securities Exchange Act of 1934) that has materially
+affected, or is reasonably likely to materially affect, our internal controls
+over financial reporting. 
+Effective April 1, 2006,
+we implemented a new enterprise resource planning system that we believe has
+not resulted in any material changes in our internal controls over financial
+reporting.
\ No newline at end of file
diff --git a/raw/filings/0000350868/2006/0001104659-07-049160/rp_note.txt b/raw/filings/0000350868/2006/0001104659-07-049160/rp_note.txt
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diff --git a/raw/filings/0000350868/2006/0001104659-07-049160/rpt_disclosure.txt b/raw/filings/0000350868/2006/0001104659-07-049160/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000350868/2008/0001104659-09-037935/filing.txt b/raw/filings/0000350868/2008/0001104659-09-037935/filing.txt
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@@ -0,0 +1,6442 @@
+10-K
+1
+a09-11714_110k.htm
+10-K
+Table of Contents 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+(Mark
+One) 
+x 
+ANNUAL
+REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
+ACT OF 1934 
+For the fiscal year ended March 31, 2009 
+OR 
+o 
+TRANSITION
+REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
+ACT OF 1934 
+For the transition period from
+to
+Commission file number 001-08762 
+ITERIS, INC. 
+(Exact Name of Registrant as Specified in Its Charter) 
+Delaware 
+95-2588496 
+(State or Other Jurisdiction 
+of Incorporation or Organization) 
+(I.R.S. Employer 
+Identification No.) 
+1700 Carnegie Ave., Santa Ana, California 92705 
+(Address of Principal Executive Offices) (Zip Code) 
+Registrant’s Telephone Number, Including Area Code: (949) 270-9400 
+Securities
+registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Name of each exchange on which registered 
+Common Stock, $0.10 par value 
+NYSE Amex 
+Securities registered
+pursuant to Section 12(g) of the Act: None 
+Indicate by check mark if the
+registrant is a well-known seasoned issuer, as defined in Rule 405 of the
+Securities Act. Yes o No x 
+Indicate by check mark if the registrant is not required to file reports
+pursuant to Section 13 or Section 15(d) of the Act. Yes o No x 
+Indicate by check mark whether the registrant (1) has filed all
+reports required to be filed by Section 13 or 15(d) of the Securities
+Exchange Act of 1934 during the preceding 12 months (or for such shorter period
+that the registrant was required to file such reports), and (2) has been
+subject to such filing requirements for the past 90 days. Yes x No o 
+Indicate by a check mark if disclosure of delinquent filers pursuant to
+Item 405 of Regulation S-K is not contained herein, and will not be contained,
+to the best of registrant’s knowledge, in definitive proxy or information
+statements incorporated by reference in Part III of this Form 10-K or
+any amendment to this Form 10-K. o 
+Indicate by check mark
+whether the registrant has submitted electronically and posted on its corporate
+Web site, if any, every Interactive Data File required to be submitted and
+posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during
+the preceding 12 months (or for such shorter period that the registrant was
+required to submit and post such files). 
+Yes x No o 
+Indicate by check mark whether the registrant is a
+large accelerated filer, an accelerated filer, a non-accelerated filer, or a
+smaller reporting company. See definitions of “large accelerated filer,” “accelerated
+filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
+(Check one): 
+Large accelerated filer o 
+Accelerated filer o 
+Non-accelerated filer o 
+Smaller reporting company x 
+(Do not check if a smaller reporting company) 
+Indicate by check mark whether the registrant is a shell company (as
+defined in Exchange Act Rule 12b-2). Yes o No x 
+Based on the closing sale price of the registrant’s common stock on the
+last business day of the registrant’s most recently completed second fiscal
+quarter, the aggregate market value of the voting common stock held by
+nonaffiliates of the registrant was approximately $44,730,000. For the purposes
+of this calculation, shares owned by officers, directors and 10% stockholders
+known to the registrant have been deemed to be owned by affiliates. This
+determination of affiliate status is not necessarily a conclusive determination
+for other purposes. 
+As of June 5, 2009, there were 34,212,756 shares of common stock
+outstanding. 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Part III incorporates by reference certain information from the
+registrant’s definitive proxy statement for the 2009 Annual Meeting of
+Stockholders, which will be filed with the Securities and Exchange Commission
+not later than 120 days after the end of the fiscal year ended March 31,
+2009. Except with respect to information specifically incorporated by reference
+in this report, the registrant’s proxy statement is not deemed to be filed as a
+part hereof. 
+Table of Contents 
+ITERIS,
+INC. 
+ANNUAL
+REPORT ON FORM 10-K 
+FOR
+THE FISCAL YEAR ENDED MARCH 31, 2009 
+TABLE OF CONTENTS 
+PART I 
+ITEM 1. 
+BUSINESS 
+2 
+ITEM 1A. 
+RISK FACTORS 
+5 
+ITEM 1B. 
+UNRESOLVED STAFF
+COMMENTS 
+13 
+ITEM 2. 
+PROPERTIES 
+14 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+14 
+ITEM 4. 
+SUBMISSION OF
+MATTERS TO A VOTE OF SECURITY HOLDERS 
+14 
+PART II 
+14 
+ITEM 5. 
+MARKET FOR
+REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES
+OF EQUITY SECURITIES 
+14 
+ITEM 6. 
+SELECTED FINANCIAL
+DATA 
+15 
+ITEM 7. 
+MANAGEMENT’S
+DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+15 
+ITEM 7A. 
+QUANTITATIVE
+AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
+27 
+ITEM 8. 
+FINANCIAL
+STATEMENTS AND SUPPLEMENTARY DATA 
+27 
+ITEM 9. 
+CHANGES IN AND
+DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+27 
+ITEM 9A(T). 
+CONTROLS AND
+PROCEDURES 
+27 
+ITEM 9B. 
+OTHER INFORMATION 
+28 
+PART III 
+28 
+ITEM 10. 
+DIRECTORS,
+EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+28 
+ITEM 11. 
+EXECUTIVE
+COMPENSATION 
+28 
+ITEM 12. 
+SECURITY
+OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
+MATTERS 
+28 
+ITEM 13. 
+CERTAIN
+RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+28 
+ITEM 14. 
+PRINCIPAL
+ACCOUNTING FEES AND SERVICES 
+29 
+PART IV 
+30 
+ITEM 15. 
+EXHIBITS AND
+FINANCIAL STATEMENT SCHEDULES 
+30 
+Unless otherwise
+indicated in this report, the “Company,” “we,” “us” and “our” refer to Iteris, Inc.
+and our wholly-owned subsidiary, Iteris Europe, GmbH. 
+AutoVue ® , Iteris ® , Vantage ® , VersiCam™, EdgeConnect™,
+Safety Direct™ and Abacus™ are among the trademarks of Iteris, Inc. Any
+other trademarks or trade names mentioned herein are the property of their
+respective owners. 
+1 
+Table of Contents 
+Cautionary
+Statement 
+This
+report, including the following discussion and analysis, contains
+forward-looking statements (within the meaning of the Private Securities
+Litigation Reform Act of 1995) that are based on our current expectations,
+estimates and projections about our business and our industry, and reflect
+management’s beliefs and certain assumptions made by us based upon information
+available to us as of the date of this report. When used in this report and the
+information incorporated herein by reference, the words “expect(s),” “feel(s),”
+“believe(s),” “should,” “would,” “could,” “may,” “anticipate(s),” “estimate(s)”
+and similar expressions or variations of these words are intended to identify
+forward-looking statements. These forward-looking statements include but are
+not limited to statements regarding our anticipated sales, revenue, expenses,
+profits, capital needs, competition, backlog and manufacturing capabilities,
+the practical market applications, future applications and acceptance of our
+products and services, the status of our facilities and product development.
+These statements are not guarantees of future performance and are subject to
+certain risks and uncertainties which could cause actual results to differ
+materially from those projected. You should not place undue reliance on these
+forward-looking statements that speak only as of the date hereof. We undertake
+no obligation to republish revised forward-looking statements to reflect events
+or circumstances after the date hereof or to reflect the occurrence of
+unanticipated events. We encourage you to carefully review and consider the
+various disclosures made by us which describe certain factors which could
+affect our business, including those in “ Risk Factors” in Item 1A
+of this report, before deciding to invest in our company or to maintain or
+increase your investment. We undertake no obligation to revise or update
+publicly any forward-looking statement for any reason. 
+PART I 
+ITEM 1. BUSINESS 
+Overview 
+We are a leader in the
+traffic management market focused on the development and application of
+advanced technologies that reduce traffic congestion and improve the safety of
+surface transportation systems infrastructure. As an added benefit, our
+products and services minimize the environmental impact of traffic congestion.
+By combining outdoor image processing, traffic engineering and information
+technology, we offer a broad range of Intelligent Transportation Systems (“ITS”)
+and driver safety solutions to customers worldwide. 
+We
+were originally incorporated in Delaware in 1987. Our principal executive offices are located
+at 1700 Carnegie Avenue, Santa Ana, California 92705, and our telephone number
+at that location is (949) 270-9400. Our
+Internet website address is www.iteris.com. 
+Our annual reports on Form 10-K, quarterly reports on Form 10-Q
+and current reports on Form 8-K, together with amendments to these
+reports, are available on the “Investors” section of our website, free of
+charge, as soon as reasonably practicable after such material is electronically
+filed with, or furnished to, the Securities and Exchange Commission (“SEC”). The inclusion of our website address in this
+report does not include or incorporate by reference into this report any
+information on our website. 
+We
+currently operate in three reportable segments: Roadway Sensors, Vehicle
+Sensors and Transportation Systems. The Roadway Sensors segment includes our
+Vantage and VersiCam vehicle detection systems for traffic
+intersection control, incident detection and certain highway traffic data
+collection applications. The Vehicle Sensors segment includes our AutoVue Lane
+Departure Warning (“LDW”) system and is comprised of all activities related to
+vehicle safety. The Transportation Systems segment includes transportation
+engineering and consulting services, and the development of transportation
+management and traveler information systems for the ITS industry. See Note 8 of
+the accompanying consolidated financial statements for further details on our
+reportable segments. 
+Our Roadway Sensors
+segment product line uses advanced image processing technology to capture and
+analyze video images through sophisticated algorithms, enabling vehicle
+detection and transmission of both video images and data using a wide range of
+communication technologies. Our Vantage
+video detection systems detect vehicle presence, count, speed, occupancy and
+other traffic data used in traffic management systems. This gives traffic managers the ability to
+mitigate roadway congestion by modifying traffic signal timing or detecting
+incidents quickly. VersiCam, our
+integrated camera and processor video detection system, is a cost-efficient
+video detection system for smaller intersections that require only a few
+detection points. Vantage video
+detection systems have been deployed by hundreds of agencies and are currently
+sold through a network of independent dealers in the United States, Asia, Latin
+America, Europe and the Middle East. 
+Our Vehicle Sensors
+segment addresses the leading cause of roadway fatalities: rear-end, lane change, and roadway departure
+accidents. According to the National
+Highway Traffic Safety Administration, these three crash types result in about
+27,500 of the U.S.’s 42,000 annual traffic fatalities and contribute to a
+considerable economic loss due to injuries, property damage, and decreased
+productivity. 
+2 
+Table of Contents 
+Our Vehicle Sensors
+segment developed the world’s first production LDW system and offers a proven
+system that is available as an original equipment manufacturer (“OEM”) and
+aftermarket option on heavy trucks worldwide and as an OEM option in passenger
+cars. Our LDW products utilize video
+detection images to detect when a vehicle begins to approach an unintended lane
+change. When this occurs, the unit
+automatically emits a distinctive rumble strip or other audible warning sound,
+alerting the driver to make a correction. 
+To date, we have sold approximately 69,000 LDW systems into the heavy
+truck market in Europe, North America and Asia. 
+Our LDW systems are currently qualified as an option on certain heavy
+trucks, including Mercedes-Benz, MAN, Iveco, DAF, Scania, Freightliner and
+FUSO, as well as Neoplan and MAN luxury bus and coach lines. In North America,
+our LDW systems are sold primarily to truck fleets, and to date, 74 U.S. heavy
+truck fleets have selected our LDW systems, with a combined fleet size
+estimated at 58,000 vehicles. Additionally,
+we have licensed our LDW technology to our strategic partner, Valeo Schalter
+and Sensuren GmbH (“Valeo”), an independent automotive supplier, resulting in
+sales to date of approximately 69,000 LDW systems for passenger cars. 
+In addition to our LDW
+systems, we expanded our Vehicle Sensors portfolio in August 2008 with
+newly developed technologies such as radar based Forward Collision Warning (“FCW”)
+and Blind Spot Warning (“BSW”) systems for the North American truck
+market. We also introduced Safety Direct
+in March 2008, which is a system that reports real-time driver performance
+data captured by our LDW system and that has the ability to relay this
+information directly to fleet operators through integration with the truck’s
+existing fleet communications system. We
+offer the FCW and BSW features through the resale of Delphi’s radar based
+systems, for which we are the exclusive North American dealer, while Safety
+Direct was internally developed. These new products, together with our LDW
+products, combine to create a broad suite of active safety driver assistance
+features that help to reduce the number of motor vehicle crashes and the
+severity of crash-related injuries. 
+Our Transportation
+Systems segment includes transportation engineering and consulting services
+focused on the planning, design, development and implementation of
+software-based systems that integrate sensors, video surveillance, computers
+and advanced communications equipment to enable public agencies to monitor,
+control and direct traffic flow, assist in the quick dispatch of emergency
+crews and distribute real-time information about traffic conditions. Our
+services include planning, design and implementation of surface transportation
+infrastructure systems. We perform
+analysis and study goods movement, commercial vehicle operations, travel demand
+forecasting and systems engineering, and identify mitigation measures to reduce
+traffic congestion. These services and
+systems are primarily sold to local, state and national transportation agencies
+in the United States. Our Transportation
+Systems segment is largely dependent upon governmental funding and budgetary
+issues. 
+Sales,
+Marketing and Principal Customers 
+We
+sell our Roadway Sensors products through indirect sales channels comprised of
+independent dealers in the United States and Canada who sell integrated systems
+and related products to the traffic management market, as well as directly to
+the traffic management market using a combination of our own sales personnel
+and an outside sales organization. Our independent dealers are primarily
+responsible for sales, installation and support of these products. These
+dealers maintain an inventory of demonstration traffic products from various
+manufacturers including our vehicle detection systems and sell directly to
+government agencies and installation contractors. These dealers often have
+long-term arrangements with the government agencies in their territory for the
+supply of various products for the construction and renovation of traffic
+intersections. We hold technical training classes for dealers and end users and
+maintain a full-time staff of customer support technicians to provide technical
+assistance when needed. 
+Our marketing strategy
+for our Vehicle Sensors segment is to establish our LDW products as the leading
+platform for in-vehicle video sensing for heavy trucks and passenger cars. We sell LDW systems directly to heavy truck
+manufacturers and to U.S. truck fleets, and our LDW system is currently offered
+as an option on certain heavy trucks, including Mercedes-Benz, MAN, Iveco, DAF,
+Scania, Freightliner and FUSO, as well as Neoplan and MAN luxury bus and coach
+lines. We market the licensing of our LDW technology to manufacturers of
+passenger automobiles through an exclusive strategic relationship with Valeo.
+In connection with this marketing effort, we provide specific contract
+engineering services, technical marketing and sales support to Valeo, which to
+date has enabled the launch of our LDW technology on three Infiniti car
+platforms. We plan to continue to provide technical marketing and sales support
+to Valeo in our efforts to win new OEM customers for the passenger car market
+as well as contract engineering services related to the possible launch of new
+platforms that include our LDW system. 
+We market and sell our
+Transportation Systems services directly to government agencies pursuant to
+negotiated contracts that involve competitive bidding and specific
+qualification requirements. Most of our Transportation Systems contracts are
+with federal, state and municipal customers and generally provide for
+cancellation or renegotiation at the option of the customer upon reasonable
+notice and fees paid for modification. We use selected members of our
+engineering team divided on a regional basis to serve in sales and business development
+functions. We have historically not engaged in sales of transportation
+management systems and traveler information services outside of the U.S., but
+may do so in the future. Our Transportation Systems contracts generally involve
+long lead times and require extensive specification development, evaluation and
+price negotiations. 
+A large portion of our
+revenues are derived from sales to federal, state and local government
+agencies. We currently have a diverse
+customer base with no individual customer representing greater than 10% of our
+total net sales and contract revenues in the fiscal year ended March 31,
+2009 (“Fiscal 2009”) or the fiscal year ended March 31, 2008 (“Fiscal 2008”).
+Also refer to Note 8 of Notes to Consolidated Financial Statements, included
+in Part IV, Item 15 of this report. 
+3 
+Table of Contents 
+Manufacturing
+and Materials 
+We use contract
+manufacturers to build subassemblies that are used in our sensors products.
+Additionally, we procure certain components from qualified suppliers, both
+globally and locally, and generally use multi-sourcing strategies when
+technically and economically feasible to mitigate supply risk. These
+subassemblies and components are delivered to our Santa Ana facility where they
+go through final assembly and testing prior to shipment to our customers.
+Certain of our key suppliers include SMS Technologies, Inc., Hitachi
+American Ltd-UB and Total Electronics LLC. Our manufacturing activities are
+conducted in approximately 9,000 square feet of space at our Santa Ana,
+California facility. Production volume at our subcontractors is based upon
+quarterly forecasts that we adjust on a monthly basis to control inventory
+levels. For LDW products sales to the passenger car market, all manufacturing
+has been and is expected to be performed by Valeo; however, we plan to continue
+to provide engineering support to Valeo. We currently do not manufacture any of
+the hardware used in the transportation management and traveler information
+systems that we design and implement. Our production facility is currently ISO
+9001 certified. 
+Customer
+Support and Services 
+We provide warranty
+service and support for our products, as well as follow-up service and support
+for which we charge separately. Service revenue accounted for less than 1.0% of
+total net sales and contract revenues for Fiscal 2009. We believe customer
+support is a key competitive factor. 
+Backlog 
+Our backlog of
+unfulfilled firm orders was approximately $36.3 million as of March 31,
+2009, which was comprised of $1.0 million related to Roadway Sensors, $800,000
+related to Vehicle Sensors and $34.5 million related to Transportation Systems.
+Substantially all of the backlog for Roadway Sensors and Vehicle Sensors is
+expected to be recognized as revenue in the fiscal year ending March 31,
+2010 (“Fiscal 2010”), while approximately 75% of Transportation Systems backlog
+is expected to be recognized as revenue in Fiscal 2010. At March 31, 2008,
+we had backlog of approximately $26.8 million, which was comprised of $900,000
+related to Roadway Sensors, $1.3 million related to Vehicle Sensors and $24.6
+million related to Transportation Systems. All backlog as of March 31,
+2008 for Roadway Sensors and Vehicle Sensors was recognized as revenue in
+Fiscal 2009 while approximately 65% of our March 31, 2008 backlog for
+Transportation Systems was recognized as revenue in Fiscal 2009. Pursuant to
+the customary terms of our agreements with government contractors and other
+customers, customers can generally cancel or reschedule orders with little
+or no penalties. Lead times for the release of purchase orders often depend
+upon the scheduling and forecasting practices of our individual customers,
+which also can affect the timing of the conversion of our backlog into
+revenues. For these reasons, among others, our backlog at a particular date may
+not be indicative of our future revenues, in particular for Roadway Sensors and
+Vehicle Sensors. 
+Product
+Development 
+Most of our development
+activities are conducted at our principal facilities in Santa Ana, California.
+Our company-sponsored research and development costs and expenses were
+approximately $4.0 million for Fiscal 2009, $3.6 million for Fiscal 2008, and
+$4.0 million for the fiscal year ended March 31, 2007 (“Fiscal 2007”). We
+expect to continue to pursue certain product development programs and incur
+research and development expenditures. 
+Competition 
+We generally face significant
+competition in each of our target markets. Increased competition may result in
+price reductions, reduced gross margins and loss of market share, any of which
+could have a material adverse effect on our business, financial condition and
+results of operations. While our LDW products have historically been the only
+established commercially-available LDW system used in the U.S. and in Europe in
+the heavy truck market, we have recently experienced increased competition from
+new competitors in this market. We consider competitors in this market to
+include Delphi Automotive Systems Corporation, NEC Corporation and Hitachi Ltd.
+in Japan and Robert Bosch GmbH in Europe, Continental Tavis, Visteon and
+Takata, which currently have developed or are developing video sensor
+technologies for the vehicle industry that could be used for lane departure
+warning systems. In the market for our Roadway Sensors vehicle detection
+products, we compete with manufacturers of other above ground video camera
+detection systems such as Econolite Control Products, Inc., Traficon,
+N.V., and other non-intrusive detection devices including microwave, infrared,
+ultrasonic and magnetic detectors, as well as manufacturers and installers of
+in-pavement inductive loop products. 
+The Transportation
+Systems market is highly fragmented and is subject to evolving national and
+regional quality and safety standards. Our competitors vary in number, scope
+and breadth of the products and services they offer. Our competitors in
+advanced Transportation Systems include national corporations such as
+Transcore, Siemens, Telvent Farradyne, Kimley-Horn and Associates, Inc.
+and Delcan. Our competitors in transportation engineering, planning and design
+include major firms such as Parsons Brinkerhoff, Inc., URS, HNTB and
+Parsons Transportation Group, Inc., as well as many smaller regional
+engineering firms. 
+4 
+Table of Contents 
+In general, the markets
+for the products and services we offer are highly competitive and are
+characterized by rapidly changing technology and evolving standards. Many of
+our current and prospective competitors have longer operating histories,
+greater name recognition, access to larger customer bases and significantly
+greater financial, technical, manufacturing, distribution and marketing
+resources than us. As a result, they may be able to adapt more quickly to new
+or emerging standards or technologies or to devote greater resources to the
+promotion and sale of their products. It is also possible that new competitors
+or alliances among competitors could emerge and rapidly acquire significant
+market share. We believe that our ability to compete effectively in our target
+markets will depend on a number of factors, including the success and timing of
+our new product development, the compatibility of our products with a broad
+range of computing systems, product quality and performance, reliability,
+functionality, price and service and technical support. Our failure to provide
+services and develop and market products that compete successfully with those
+of other suppliers and consultants in our target markets would have a material
+adverse effect on our business, financial condition and results of operations. 
+Intellectual
+Property and Proprietary Rights 
+Our ability to compete
+effectively depends in part on our ability to develop and maintain the
+proprietary aspects of our technology. Our policy is to obtain appropriate
+proprietary rights protection for any potentially significant new technology
+acquired or developed by us. We currently hold ten U.S. patents, which expire
+commencing in 2012, relating to our outdoor image processing techniques used in
+our AutoVue LDW systems. Nine of our patents relate specifically to our LDW
+technology and provide a basis for enhanced functionality for rain sensing and
+improved performance. We believe that our other patent, while important for our
+technology platforms, is less critical to our near term product strategy. In April 2009, we acquired the rights to
+U.S., Canadian, and European Community patent applications for an Electronic
+Traffic Monitor that is related to new products in our Roadway Sensors
+businesses (also refer to Note 10 of Notes to Consolidated Financial
+Statements, included in Part IV, Item 15 of this report). We cannot
+assure you that any new patents will be granted pursuant to these or subsequent
+applications. 
+In addition to patent
+laws, we rely on copyright and trade secret laws to protect our proprietary
+rights. We attempt to protect our trade secrets and other proprietary
+information through agreements with customers and suppliers, proprietary
+information agreements with our employees and consultants, and other similar
+measures. We do not have any material licenses or trademarks other than those
+relating to product names. We cannot be certain that we will be successful in
+protecting our proprietary rights. While we believe our patents, patent
+applications, software and other proprietary know-how have value, changing
+technology makes our future success dependent principally upon our employees’
+technical competence and creative skills for continuing innovation. 
+Litigation may be
+necessary in the future to enforce our proprietary rights, to determine the
+validity and scope of the proprietary rights of others, or to defend us against
+claims of infringement or invalidity by others. An adverse outcome in such
+litigation or similar proceedings could subject us to significant liabilities
+to third parties, require disputed rights to be licensed from others or require
+us to cease marketing or using certain products, any of which could have a
+material adverse effect on our business, financial condition and results of
+operations. In addition, the cost of addressing any intellectual property
+litigation claim, both in legal fees and expenses, as well as from the
+diversion of management’s resources, regardless of whether the claim is valid,
+could be significant and could have a material adverse effect on our business,
+financial condition and results of operations. 
+Employees 
+We refer to our employees
+as associates. As of June 1, 2009, we employed an aggregate of 242
+associates, including 55 associates in general management, administration and
+finance; 22 associates in sales and marketing; 132 associates in engineering
+and product development; 20 associates in operations, manufacturing and
+quality; and 13 associates in customer service. None of our associates are
+represented by a labor union, and we have never experienced a work stoppage. 
+Government
+Regulation 
+Our manufacturing
+operations are subject to various federal, state and local laws and
+regulations, including those restricting the discharge of materials into the
+environment. We are not involved in any pending or, to our knowledge,
+threatened governmental proceedings, which would require curtailment of our
+operations because of such laws and regulations. We continue to expend funds in
+connection with our compliance with applicable environmental regulations. These
+expenditures have not, however, been significant in the past, and we do not
+expect any significant expenditure in the near future. Currently, compliance
+with foreign laws has not had a material impact on our business and is not expected
+to have a material impact in the near future. 
+ITEM 1A. RISK
+FACTORS 
+Our
+business is subject to a number of risks, some of which are discussed below.
+Other risks are presented elsewhere in this report and in the information
+incorporated by reference into this report. You should consider the following
+risks carefully in addition to the other information contained in this report
+and our other filings with the SEC, including our annual report on Form 10-K
+and subsequent reports on Forms 10-Q and 8-K, before deciding to buy, sell, or
+hold our common stock. The risks and uncertainties described below are not the
+only ones facing our company. Additional risks and uncertainties not presently
+known to us or that we currently deem immaterial may also affect our business
+operations. If any of these risks actually occurs, our business, financial
+condition, or results of operations could be seriously harmed. In that event,
+the market price for our common stock could decline and you may lose all or
+part of your investment. 
+5 
+Table of Contents 
+THE
+ECONOMIC SLOWDOWN HAS ADVERSELY IMPACTED REAL ESTATE DEVELOPMENT, REDUCED OR
+DELAYED GOVERNMENT FUNDING FOR TRANSPORTATION INFRASTRUCTURE PROJECTS AND
+INITIATIVES AND DECREASED AVAILABILITY OF FINANCIAL CAPITAL FOR OUR CUSTOMERS,
+ALL OF WHICH HAVE ADVERSELY IMPACTED OUR NET SALES AND COULD IMPACT OUR
+CONTRACT REVENUES. Decreased consumer spending, the failure
+of certain financial institutions and businesses, concerns about the
+availability and cost of credit, and reduced corporate profits and capital
+spending have resulted in a downturn in worldwide economic conditions, as well
+as budgetary shortfalls increasingly present at all levels of government. These
+unfavorable economic conditions have had a negative impact on customer orders
+and government funding of infrastructure projects incorporating our products
+and services. Such concerns may result in cancellations and rescheduling of
+backlog. In addition, the recent decline in the U.S. real estate market,
+particularly in new home and commercial construction, has adversely impacted
+new road construction and has resulted in and may continue to result in flat or
+slightly declining Roadway Sensor and Vehicle Sensor net sales and could
+adversely impact Transportation Systems contract revenues. Any of the foregoing
+economic conditions make it extremely difficult for our customers, our
+suppliers and us to accurately forecast and plan future business activities. If
+such conditions continue or worsen, our business, financial condition and
+results of operations could be materially and adversely affected. 
+BECAUSE
+WE DEPEND ON GOVERNMENT CONTRACTS AND SUBCONTRACTS, WE FACE ADDITIONAL RISKS
+RELATED TO CONTRACTING WITH FEDERAL, STATE AND LOCAL GOVERNMENTS, INCLUDING
+BUDGETARY ISSUES AND FIXED PRICE CONTRACTS. A significant portion of our sales are derived from
+contracts with governmental agencies, either as a general contractor,
+subcontractor or supplier. Government contracts represented approximately 45%,
+38% and 38% of our total net sales and contract revenues for the years ended March 31,
+2009, 2008 and 2007, respectively. We anticipate that revenue from government
+contracts will continue to remain a significant portion of our net sales and
+contract revenues. Government business is, in general, subject to special risks
+and challenges, including: 
+· 
+long purchase
+cycles or approval processes; 
+· 
+competitive
+bidding and qualification requirements; 
+· 
+the impact of
+international conflicts; 
+· 
+delays in
+funding, including delays in the allocation of funds to state and local
+agencies from the U.S. federal government as a result of the expiration of
+the 2005 Federal Highway Bill occurring in September 2009; 
+· 
+performance bond
+requirements; 
+· 
+changes in
+government policies and political agendas; 
+· 
+other government
+budgetary constraints, cut-backs, delays or reallocation of government
+funding; and 
+· 
+milestone
+requirements and liquidated damage provisions for failure to meet contract
+milestones. 
+Governmental budgets and
+plans are subject to change without warning. Certain risks of selling to
+governmental entities include dependence on appropriations and administrative
+allocation of funds, changes in governmental procurement legislation and
+regulations and other policies that may reflect political developments or
+agendas, significant changes in contract scheduling, intense competition for
+government business and termination of purchase decisions for the convenience
+of the governmental entity. Substantial delays in purchase decisions by
+governmental entities, or governmental budgetary constraints, could cause our
+net sales and contract revenues and income to drop substantially or to
+fluctuate significantly between fiscal periods. 
+In
+addition, a large number of our government contracts are fixed price contracts.
+As a result, we may not be able to recover any cost overruns we may incur.
+These fixed price contracts require us to estimate the total project cost based
+on preliminary projections of the project’s requirements. The financial
+viability of any given project depends in large part on our ability to estimate
+these costs accurately and complete the project on a timely basis. In the event
+our costs on these projects exceed the fixed contractual amount, we will be
+required to bear the excess costs. Such additional costs would adversely affect
+our financial condition and results of operations. Moreover, certain of our
+government contracts are subject to termination or renegotiation at the
+convenience of the government, which could result in a large decline in our net
+sales and contract revenues in any given quarter. Our inability to address any
+of the foregoing concerns or the loss or renegotiation of any material
+government contract could seriously harm our business, financial condition and
+results of operations. 
+6 
+Table of Contents 
+CURRENT BUDGETARY CONSTRAINTS DUE TO THE SIGNIFICANT MILITARY
+OPERATIONS IN THE MIDDLE EAST OR ELSEWHERE MAY IMPACT GOVERNMENT FUNDING
+OR CONSUMER SPENDING, CAUSING A DECLINE IN OUR REVENUES. In the near term, the funding of U.S.
+military operations in the Middle East or elsewhere may cause additional
+disruptions in funding of government contracts. Since military operations of
+such magnitude are not routinely included in U.S. defense budgets, supplemental
+legislative funding actions are often required to finance such operations. Even
+when such legislation is enacted, it may not be adequate for ongoing
+operations, causing other government resources to be temporarily or permanently
+diverted. Since a significant portion of our sales are derived from contracts
+with government agencies, such diversion of funds could produce interruptions
+in funding or delays in receipt of our contracts, causing disruptions and
+adversely effecting our revenue and operations. 
+THE
+MARKETS IN WHICH WE OPERATE ARE HIGHLY COMPETITIVE AND HAVE MANY MORE
+ESTABLISHED COMPETITORS, WHICH COULD ADVERSELY AFFECT OUR SALES OR THE MARKET
+ACCEPTANCE OF OUR PRODUCTS. We compete with numerous other companies in our target
+markets including, but not limited to, large, multinational corporations, which
+include tier one automotive suppliers, and many smaller regional engineering
+firms. We expect such competition to increase due to technological
+advancements, industry consolidations and reduced barriers to entry. Increased
+competition is likely to result in price reductions, reduced gross margins and
+loss of market share, any of which could seriously harm our business, financial
+condition and results of operations. In Fiscal 2007, we began to experience
+more competition in our Roadway Sensors segment as the Department of
+Transportation in one of our largest sales territories moved to a multi-source
+contracting environment from one in which we were the sole supplier. In
+addition, one of the other developers of LDW systems was acquired by a large
+multinational organization during Fiscal 2009. This new competitor has
+increased its market share and could be more aggressive in both the passenger
+car and heavy truck markets, as a result of its greater access to resources and
+reputation in the market. As a result, we have experienced increased price
+competition, which could erode our margins. Additional new competitors have
+entered this market and more competitors may enter in the future. Furthermore,
+awareness of LDW technology is increasing and other market players have
+developed competing technologies, which may contain improvements or added
+features beyond those offered by our LDW systems. Additionally, from time to
+time, we may be required to re-compete for LDW business from our main customer
+base of heavy truck OEMs. These OEMs could make a supplier change based on
+price, product performance or available features. Should our competition be
+successful, this could adversely affect our ability to successfully market and
+sell our LDW systems to new and existing customers. 
+Many
+of our competitors have far greater name recognition and greater financial,
+technological, marketing, and customer service resources than we do. This may
+allow them to respond more quickly to new or emerging technologies and changes
+in customer requirements. It may also allow them to devote greater resources to
+the development, promotion, sale and support of their products than we can.
+Recent consolidations of end users, distributors and manufacturers in our
+target markets have exacerbated this problem. As a result of the foregoing
+factors, we may not be able to compete effectively in our target markets and
+competitive pressures could adversely affect our business, financial condition
+and results of operations. 
+WE MAY EXPERIENCE
+PRODUCTION GAPS THAT COULD MATERIALLY AND ADVERSELY IMPACT OUR SALES AND
+FINANCIAL RESULTS AND THE ULTIMATE ACCEPTANCE OF OUR PRODUCTS. It is possible that we could experience
+unforeseen quality control issues or part shortages as we adjust production to
+meet current demand for our products. We have historically used single
+suppliers for certain significant components in our products. Should any such
+delay or disruption occur, or should a key supplier discontinue operations because
+of the current economic climate, our future sales will likely be materially and
+adversely affected. Additionally, we rely heavily on select contract
+manufacturers to produce many of our products and do not have any long-term
+contracts to guarantee supply of such products. Although we believe our
+contract manufacturers have sufficient capacity to meet our production
+schedules for the foreseeable future and we believe we could find alternative
+contract manufacturing sources for many of our products, if necessary, we could
+experience a production gap if for any reason our contract manufacturers were
+unable to meet our production requirements and our cost of good sold could
+increase, adversely affecting our margins. 
+WE MAY BE
+UNABLE TO ATTRACT AND RETAIN KEY PERSONNEL, WHICH COULD SERIOUSLY HARM OUR
+BUSINESS. Due to
+the specialized nature of our business, we are highly dependent on the
+continued service of our executive officers and other key management,
+engineering and technical personnel. The loss of Abbas Mohaddes, our Chief
+Executive Officer, or any of the other executive officers or key members of
+management could adversely affect our business, financial condition, or results
+of operations. Our success will also depend in large part upon our ability to
+continue to attract, retain and motivate qualified engineering and other highly
+skilled technical personnel. In particular, the future success of our
+Transportation Systems segment will depend on our ability to hire additional
+qualified engineers and planners. Competition for qualified employees,
+particularly development engineers, is intense. We may not be able to continue
+to attract and retain sufficient numbers of such highly skilled employees. Our
+inability to attract and retain additional key employees or the loss of one or
+more of our current key employees could adversely affect our business,
+financial condition and results of operations. 
+7 
+Table of Contents 
+IF WE ARE
+UNABLE TO DEVELOP AND INTRODUCE NEW PRODUCTS AND PRODUCT ENHANCEMENTS
+SUCCESSFULLY AND IN A COST-EFFECTIVE AND TIMELY MANNER, OR ARE UNABLE TO
+ACHIEVE MARKET ACCEPTANCE OF OUR NEW PRODUCTS, OUR OPERATING RESULTS WOULD BE
+ADVERSELY AFFECTED. We
+believe our revenue growth and future operating results will depend on our
+ability to complete development of new products and enhancements, introduce
+these products in a timely, cost-effective manner, achieve broad market acceptance
+of these products and enhancements, and reduce our product costs. We cannot
+guarantee the success of these products, and we may not be able to introduce
+any new products or any enhancements to our existing products on a timely
+basis, or at all. In addition, the introduction of any new products could
+adversely affect the sales of certain of our existing products. 
+We
+believe that we must continue to make substantial investments to support
+ongoing research and development in order to remain competitive. We need to
+continue to develop and introduce new products that incorporate the latest
+technological advancements in outdoor image processing hardware, software and
+camera technologies in response to evolving customer requirements. We cannot
+assure you that we will be able to adequately manage product transition issues.
+Our business and results of operations could be adversely affected if we do not
+anticipate or respond adequately to technological developments or changing
+customer requirements or if we cannot adequately manage inventory issues
+typically related to new product transitions and introductions. We cannot
+assure you that any such investments in research and development will lead to
+any corresponding increase in revenue. 
+Market
+acceptance of our new products depends upon many factors, including our ability
+to accurately predict market requirements and evolving industry standards, our
+ability to resolve technical challenges in a timely and cost-effective manner,
+qualify any new products with OEMs and achieve manufacturing efficiencies, the
+perceived advantages of our new products over traditional products and the
+marketing capabilities of our independent distributors and strategic partners,
+including Valeo’s ability to expand sales of LDW systems in the passenger car
+market. The success of our LDW system will also depend in part on the success
+of the automotive vehicles that incorporate our technology, as well as the
+success of optional equipment that OEMs bundle with our technologies. 
+Certain
+of the components used in our products may need to be re-engineered in the next
+12 to 36 months as the industry is moving towards a standard of using lead-free
+components. We cannot assure you as to the timing of the adoption of this new
+standard or our ability to successfully redesign our products to incorporate
+compliant components and gain market acceptance of such redesigned products. In
+addition, if the standard is adopted earlier than anticipated we may experience
+a shortage of products as a result of potential scarcity of lead-free
+components. 
+Our
+business and results of operations could also be seriously harmed by any
+significant delays in our new product development. Certain of our new products
+could contain undetected design faults and software errors or “bugs” when first
+released by us, despite our testing. We may not discover these faults or errors
+until after a product has been installed and used by our customers. Any faults
+or errors in our existing products or in any new products may cause delays in
+product introduction and shipments, require design modifications or harm
+customer relationships, any of which could adversely affect our business and
+competitive position. 
+NEW ENVIRONMENTAL REGULATIONS MAY RESULT IN A DECLINE IN
+OUR VEHICLE SENSORS NET SALES. From time to time,
+environmental regulations are enacted, which can significantly increase the
+cost of manufacturing new vehicles as well as the cost of maintenance of
+existing vehicles and truck fleets. As a
+result, we could experience a decline in sales of our Vehicle Sensors products
+as truck and vehicle manufacturers and fleet operators attempt to control their
+costs. 
+WE MAY ENGAGE
+IN ACQUISITIONS OF COMPANIES OR TECHNOLOGIES THAT MAY REQUIRE US TO
+UNDERTAKE SIGNIFICANT CAPITAL INFUSIONS AND COULD RESULT IN DISRUPTIONS OF OUR
+BUSINESS AND DIVERSION OF RESOURCES AND MANAGEMENT ATTENTION. We have in the past acquired, and may in
+the future acquire, complementary businesses, products, and technologies.
+Acquisitions may require significant capital infusions and, in general,
+acquisitions also involve a number of special risks, including: 
+· 
+potential
+disruption of our ongoing business and the diversion of our resources and
+management’s attention; 
+· 
+the failure to
+retain or integrate key acquired personnel; 
+· 
+the challenge of
+assimilating diverse business cultures, and the difficulties in integrating
+the operations, technologies and information system of the acquired
+companies; 
+· 
+increased costs
+to improve managerial, operational, financial and administrative systems and
+to eliminate duplicative services; 
+· 
+the incurrence
+of unforeseen obligations or liabilities; 
+· 
+potential
+impairment of relationships with employees or customers as a result of
+changes in management; and 
+· 
+increased
+interest expense and amortization of acquired intangible assets. 
+Our
+competitors are also soliciting potential acquisition candidates, which could
+both increase the price of any acquisition targets and decrease the number of
+attractive companies available for acquisition. Acquisitions may also
+materially and adversely affect our operating results due to large write-offs,
+contingent liabilities, substantial depreciation, deferred compensation charges
+or intangible asset amortization, or other adverse tax or accounting
+consequences. We cannot assure you that we will be able to identify or consummate
+any additional acquisitions, successfully integrate any acquisitions or realize
+the benefits anticipated from any acquisition. 
+8 
+Table of Contents 
+WE DEPEND
+UPON VALEO TO MARKET OUR LDW TECHNOLOGIES FOR THE OEM PASSENGER CAR MARKET. We have granted Valeo the exclusive right
+to sell and manufacture our LDW system to the worldwide passenger car market in
+exchange for royalty payments for each LDW unit sold. As such, the future
+success and broad market acceptance of our technologies in the passenger car
+market will depend upon Valeo’s ability to manufacture market and sell our
+technologies, and to convince more OEM passenger car manufacturers to adopt our
+technologies. To date, we have not
+generated significant royalties from Valeo’s efforts and have only been
+designed into one car OEM product line. 
+If Valeo does not devote considerable resources and aggressively pursue
+opportunities, our expansion into the passenger car market could be adversely
+affected. 
+IF WE DO
+NOT KEEP PACE WITH RAPID TECHNOLOGICAL CHANGES AND EVOLVING INDUSTRY STANDARDS,
+WE WILL NOT BE ABLE TO REMAIN COMPETITIVE AND THERE WILL BE NO DEMAND FOR OUR
+PRODUCTS. Our
+markets are in general characterized by the following factors: 
+· 
+rapid
+technological advances; 
+· 
+downward price
+pressure in the marketplace as technologies mature; 
+· 
+changes in
+customer requirements; 
+· 
+additional
+qualification requirements related to new products or components; 
+· 
+frequent new
+product introductions and enhancements; 
+· 
+inventory issues
+related to transition to new or enhanced models; and 
+· 
+evolving
+industry standards and changes in the regulatory environment. 
+Our
+future success will depend upon our ability to anticipate and adapt to changes
+in technology and industry standards, and to effectively develop, introduce,
+market and gain broad acceptance of new products and product enhancements
+incorporating the latest technological advancements. In particular, our LDW
+systems are incorporated into automobiles and trucks that face significant
+technological changes in each model year and among different vehicle models.
+Accordingly, we must adapt our technology from time to time to function with
+such changes. 
+OUR
+INTERNATIONAL BUSINESS OPERATIONS MAY BE THREATENED BY MANY FACTORS THAT
+ARE OUTSIDE OF OUR CONTROL. We currently market our products internationally and
+we anticipate that our international operations will expand in the near future.
+International business operations are subject to various inherent risks
+including, among others: 
+· 
+currency
+fluctuations and restrictions; 
+· 
+political,
+social and economic instability; 
+· 
+longer accounts
+receivable payment cycles; 
+· 
+import and
+export license requirements and restrictions of the United States and each
+other country in which we operate; 
+· 
+unexpected
+changes in regulatory requirements, tariffs and other trade barriers or
+restrictions; 
+· 
+the burdens of
+compliance with a wide variety of foreign laws and more restrictive labor
+laws and obligations; 
+· 
+difficulties in
+managing and staffing international operations; 
+· 
+potentially
+adverse tax consequences; and 
+· 
+reduced
+protection for intellectual property rights in some countries. 
+All of
+our international sales are denominated in U.S. dollars. As a result, an increase
+in the relative value of the dollar could make our products more expensive and
+potentially less price competitive in international markets. We do not engage
+in any transactions as a hedge against risks of loss due to foreign currency
+fluctuations. 
+9 
+Table of Contents 
+Any of
+the factors mentioned above may adversely affect our future international sales
+and, consequently, affect our business, financial condition and operating
+results. Furthermore, as we increase our international sales, our total
+revenues may also be affected to a greater extent by seasonal fluctuations
+resulting from lower sales that typically occur during the summer months in
+Europe and other parts of the world. 
+IF OUR INTERNAL CONTROLS OVER
+FINANCIAL REPORTING DO NOT COMPLY WITH THE REQUIREMENTS OF THE SARBANES-OXLEY
+ACT, OUR BUSINESS AND STOCK PRICE COULD BE ADVERSELY AFFECTED. Section 404 of the Sarbanes-Oxley Act of 2002
+currently requires us to evaluate the effectiveness of our internal controls
+over financial reporting at the end of each fiscal year and to include a
+management report assessing the effectiveness of our internal controls over
+financial reporting in all annual reports. Beginning with Fiscal 2010, our
+independent registered public accounting firm will also be required to attest
+to, and report on, the effectiveness of our internal controls over financial
+reporting. We may not be able to complete the work required for such
+attestation on a timely basis, and even if we timely complete such
+requirements, our independent auditors may still conclude that our internal
+controls over financial reporting are not effective. 
+Our
+management, including our CEO and CFO, does not expect that our internal
+controls over financial reporting will prevent all errors and all fraud. A
+control system, no matter how well designed and operated, can provide only
+reasonable, not absolute, assurance that the control system’s objectives will
+be met. Further, the design of a control system must reflect the fact that
+there are resource constraints, and the benefits of controls must be considered
+relative to their costs. Because of the inherent limitations in all control
+systems, no evaluation of controls can provide absolute assurance that all
+control issues and instances of fraud, if any, within Iteris have been or will
+be detected. These inherent limitations include the realities that judgments in
+decision-making can be faulty and that breakdowns can occur because of simple
+errors or mistakes. Controls can also be circumvented by the individual acts of
+some persons, by collusion of two or more people, or by management override of
+the controls. The design of any system of controls is based in part on certain
+assumptions about the likelihood of future events, and we cannot assure you
+that any design will succeed in achieving its stated goals under all potential
+future conditions. Over time, our controls may become inadequate because of
+changes in conditions or deterioration in the degree of compliance with
+policies or procedures. Because of the inherent limitations in a cost-effective
+control system, misstatements due to error or fraud may occur and not be
+detected. 
+WE MAY NEED
+TO RAISE ADDITIONAL CAPITAL IN THE FUTURE, WHICH MAY NOT BE AVAILABLE ON
+TERMS ACCEPTABLE TO US, OR AT ALL. Until recently, we have historically
+generated significant net losses and operating losses, and have experienced
+volatility in our cash flows from operations from year to year. Although we
+entered into a new $19.5 million credit facility, effective October 2008,
+should we have an event of default, which includes, among other things, a
+failure to meet certain financial covenants and a material adverse change in
+the business, the bank could choose to limit or take away our ability to borrow
+these or any funds. Should this occur,
+or if the credit markets further tighten, we may need or choose to raise
+additional capital to refinance the remaining debentures, pursue acquisitions
+or to expand our operations. 
+At March 31, 2009, we had $6.4 million of cash and cash
+equivalents and our entire $12.0 million line of credit to fund our operations.
+We may need to raise additional capital in the near future to fund our
+operations or to repay indebtedness. Such additional capital may be raised
+through bank borrowings, or other debt or equity financings. We cannot assure
+you that any additional capital will be available on a timely basis, on
+acceptable terms, or at all, and such additional financing may result in
+further dilution to our stockholders. 
+Our
+capital requirements will depend on many factors, including, but not limited
+to: 
+· 
+market
+acceptance of our products and product enhancements, and the overall level of
+sales of our products; 
+· 
+our ability to
+control costs; 
+· 
+the supply of
+key components for our products; 
+· 
+our ability to
+increase revenue and net income; 
+· 
+increased
+research and development expenses and sales and marketing expenses; 
+· 
+our need to
+respond to technological advancements and our competitors’ introductions of
+new products or technologies; 
+· 
+capital
+improvements to new and existing facilities and enhancements to our
+infrastructure and systems; 
+· 
+potential
+acquisitions of businesses and product lines; 
+10 
+Table of Contents 
+· 
+our
+relationships with customers and suppliers; 
+· 
+government
+budgets, political agendas and other funding issues, including potential
+delays in government contract awards; 
+· 
+our ability to
+successfully negotiate credit arrangements with our bank and repay our
+subordinated convertible debentures; and 
+· 
+general economic
+conditions, including the effects of the current economic slowdown and
+international conflicts. 
+If our
+capital requirements are materially different from those currently planned, we
+may need additional capital sooner than anticipated. If additional funds are
+raised through the issuance of equity or convertible debt securities, the percentage
+ownership of our stockholders will be reduced and such securities may have
+rights, preferences and privileges senior to our common stock. Additional
+financing may not be available on favorable terms, on a timely basis, or at
+all. If adequate funds are not available or are not available on acceptable
+terms, we may be unable to continue our operations as planned, develop or
+enhance our products, expand our sales and marketing programs, take advantage
+of future opportunities or respond to competitive pressures. 
+OUR
+QUARTERLY OPERATING RESULTS FLUCTUATE AS A RESULT OF MANY FACTORS. THEREFORE,
+WE MAY FAIL TO MEET OR EXCEED THE EXPECTATIONS OF SECURITIES ANALYSTS AND
+INVESTORS, WHICH COULD CAUSE OUR STOCK PRICE TO DECLINE. Our quarterly revenues and operating
+results have fluctuated and are likely to continue to vary from quarter to
+quarter due to a number of factors, many of which are not within our control.
+Factors that could affect our revenues include, among others, the following: 
+· 
+changes in our
+pricing policies and the pricing policies of our suppliers and competitors,
+pricing concessions on volume sales, as well as increased price competition
+in general; 
+· 
+the long lead
+times associated with government contracts or required by vehicle manufacturers; 
+· 
+the size,
+timing, rescheduling or cancellation of significant customer orders; 
+· 
+delays in
+government contracts and funding from time to time and budgetary constraints
+at the federal, state and local levels; 
+· 
+declines in new
+home construction and related road and other infrastructure construction; 
+· 
+our ability to
+control costs; 
+· 
+our ability to
+raise additional capital; 
+· 
+the mix of our
+products and services sold in a quarter, which mix has varied and is expected
+to continue to vary from time to time; 
+· 
+seasonality due
+to winter weather conditions; 
+· 
+international
+conflicts and acts of terrorism; 
+· 
+our ability to
+develop, introduce, patent, market and gain market acceptance of new
+products, applications and product enhancements in a timely manner, or at
+all; 
+· 
+market
+acceptance of the products incorporating our technologies and products; 
+· 
+the introduction
+of new products by competitors; 
+· 
+the availability
+and cost of components used in the manufacture of our products; 
+· 
+our success in
+expanding and implementing our sales and marketing programs; 
+11 
+Table
+of Contents 
+· 
+the effects of
+technological changes in our target markets; 
+· 
+the amount of
+our backlog at any given time; 
+· 
+the nature of
+our government contracts; 
+· 
+deferrals of
+customer orders in anticipation of new products, applications or product
+enhancements; 
+· 
+risks and
+uncertainties associated with our international business; 
+· 
+currency
+fluctuations and our ability to get currency out of certain foreign
+countries; and 
+· 
+general economic
+and political conditions. 
+Due to
+all of the factors listed above as well as other unforeseen factors, our future
+operating results could be below the expectations of securities analysts or
+investors. If that happens, the trading price of our common stock could
+decline. As a result of these quarterly variations, you should not rely on
+quarter-to-quarter comparisons of our operating results as an indication of our
+future performance. 
+WE HAVE EXPERIENCED GROWTH IN RECENT PERIODS. IF WE
+FAIL TO MANAGE OUR GROWTH EFFECTIVELY, WE MAY BE UNABLE TO EXECUTE OUR
+BUSINESS PLAN AND MAY EXPERIENCE FUTURE WEAKNESSES IN OUR INTERNAL
+CONTROLS. We have
+expanded our overall business in the past few years. In order to achieve our
+business objectives, we will need to continue to expand our business and add
+additional qualified personnel. Such expansion has placed and is expected to
+continue to place, a significant strain on our managerial, administrative,
+operational, financial and other resources. If we are unable to successfully
+manage our growth, our business, financial condition and results of operations
+will be adversely affected. 
+WE MAY NOT
+BE ABLE TO ADEQUATELY PROTECT OR ENFORCE OUR INTELLECTUAL PROPERTY RIGHTS,
+WHICH COULD HARM OUR COMPETITIVE POSITION. If we are not able to adequately protect or enforce
+the proprietary aspects of our technology, competitors could be able to access
+our proprietary technology and our business, financial condition and results of
+operations will likely be seriously harmed. We currently attempt to protect our
+technology through a combination of patent, copyright, trademark and trade
+secret laws, employee and third party nondisclosure agreements and similar
+means. Despite our efforts, other parties may attempt to disclose, obtain or
+use our technologies or systems. Our competitors may also be able to
+independently develop products that are substantially equivalent or superior to
+our products or design around our patents. In addition, the laws of some
+foreign countries do not protect our proprietary rights as fully as do the laws
+of the United States. As a result, we may not be able to protect our
+proprietary rights adequately in the United States or abroad. 
+Litigation may be
+necessary in the future to enforce our intellectual property rights or to
+determine the validity and scope of the proprietary rights of others.
+Litigation may also be necessary to defend against claims of infringement or
+invalidity by others. An adverse outcome in litigation or any similar
+proceedings could subject us to significant liabilities to third parties,
+require us to license disputed rights from others or require us to cease
+marketing or using certain products or technologies. We may not be able to
+obtain any licenses on terms acceptable to us, or at all. We also may have to
+indemnify certain customers or strategic partners if it is determined that we
+have infringed upon or misappropriated another party’s intellectual property.
+Any of these results could adversely affect our business, financial condition
+and results of operations. In addition, the cost of addressing any intellectual
+property litigation claim, including legal fees and expenses, and the diversion
+of management’s attention and resources, regardless of whether the claim is
+valid, could be significant and could seriously harm our business, financial
+condition and results of operations. 
+WE HAVE HISTORICALLY EXPERIENCED
+SUBSTANTIAL LOSSES AND MAY EXPERIENCE LOSSES IN THE FUTURE. Although we have achieved net income in
+our past four fiscal years, we experienced a net loss of $11.3 million in the
+year ended March 31, 2005 and significant net losses in prior years. We
+cannot assure you that we will be able to sustain or improve our financial
+performance, or that we will be able to continue to achieve profitability on a
+quarterly or annual basis in the future. Most of our expenses are fixed in
+advance. As such, we generally are unable to reduce our expenses significantly
+in the short-term to compensate for any unexpected delay or decrease in
+anticipated revenues. As a result, we may continue to experience operating losses
+and net losses, which would make it difficult to fund our operations and
+achieve our business plan, and could cause the market price of our common stock
+to decline. 
+THE
+TRADING PRICE OF OUR COMMON STOCK IS HIGHLY VOLATILE. The trading price of our common stock has
+been subject to wide fluctuations in the past. Since February 2001, our Class A
+common stock (now known as our common stock) has traded at prices as low as
+$0.45 per share and as high as $6.12 per share. The market price of our common
+stock could continue to fluctuate in the future in response to various factors,
+including, but not limited to: 
+12 
+Table of Contents 
+· 
+quarterly
+variations in operating results; 
+· 
+our ability to
+control costs, improve cash flow and sustain profitability; 
+· 
+our ability to
+raise additional capital; 
+· 
+shortages
+announced by suppliers; 
+· 
+announcements of
+technological innovations or new products or applications by our competitors,
+customers or us; 
+· 
+transitions to
+new products or product enhancements; 
+· 
+acquisitions of
+businesses, products or technologies; 
+· 
+the impact of
+any litigation; 
+· 
+changes in
+investor perceptions; 
+· 
+government
+funding, political agendas and other budgetary constraints; 
+· 
+changes in
+earnings estimates or investment recommendations by securities analysts; and 
+· 
+international
+conflicts, political unrest and acts of terrorism. 
+The stock
+market in general has from time to time experienced volatility, which has often
+affected the market prices of equity securities of many technology companies.
+This volatility has often been unrelated to the operating performance of these
+companies. These broad market fluctuations may adversely affect the market
+price of our common stock. In the past, companies that have experienced
+volatility in the market price of their securities have been the subject of
+securities class action litigation. If we were to become the subject of a class
+action lawsuit, it could result in substantial losses and divert management’s
+attention and resources from other matters. 
+WE COULD
+EXPERIENCE NEGATIVE FINANCIAL IMPACTS ARISING FROM DEVELOPMENTS IN
+CONTINGENCIES CREATED UNDER OUR PREVIOUS STRUCTURE OR BY FORMER SUBSIDIARIES. Although we divested ourselves of all
+business units prior to October 2004, from time to time we could
+experience unforeseen developments in contingencies related to our former
+subsidiaries. For example, in July 2006 we entered into a settlement
+agreement in connection with a lawsuit brought against Mariner Networks, Inc.,
+one of our former subsidiaries, by one of Mariner’s suppliers, pursuant to
+which we issued 88,912 shares of our common stock to this supplier (valued at
+$213,000 as of the date of issuance), paid this supplier $125,000 on October 20,
+2006 and are required to pay an additional $350,000 in 36 equal monthly
+installments of $9,700 through October 2009. Although we are not aware of
+any other material contingencies, it is possible other matters could be brought
+against us in connection with activities related to former subsidiaries and
+that such matters could materially and adversely affect our financial results
+and cash flows. 
+CERTAIN PROVISIONS OF THE COMPANY’S CHARTER DOCUMENTS MAY DISCOURAGE
+A THIRD PARTY FROM ACQUIRING US AND MAY ADVERSELY AFFECT THE PRICE OF OUR
+COMMON STOCK. Certain
+provisions of our certificate of incorporation could make it difficult for a
+third party to acquire us, even though an acquisition might be beneficial to
+our stockholders. Such provisions could limit the price that investors might be
+willing to pay in the future for shares of our common stock. Under the terms of
+our certificate of incorporation, our Board of Directors is authorized to
+issue, without stockholder approval, up to 2,000,000 shares of preferred stock
+with voting, conversion and other rights and preferences superior to those of
+our common stock. Our future issuance of preferred stock also could be used to
+effect a stockholder rights plan, which could discourage an unsolicited
+acquisition proposal. 
+ITEM 1B. UNRESOLVED
+STAFF COMMENTS 
+None. 
+13 
+Table of Contents 
+ITEM 2. PROPERTIES 
+Our headquarters and
+principal operations are housed in approximately 52,000 square feet of leased
+space located at 1700 Carnegie Avenue, Santa Ana, California, for which we
+currently pay a monthly base lease rate of approximately $105,000, exclusive of
+certain utility and other costs. The Santa Ana facility lease expires in 2015
+and contains an option to extend the lease for an additional five years at the
+market rate at that time. 
+For additional information
+regarding our obligations under property leases, see Note 5 of Notes to
+Consolidated Financial Statements, included in Part IV, Item 15 of this
+report. 
+ITEM 3. LEGAL
+PROCEEDINGS 
+The information set forth
+under the heading “Litigation” under Note 5 of Notes to Consolidated Financial
+Statements, included in Part IV, Item 15 of this report, is incorporated
+herein by reference. 
+ITEM 4. SUBMISSION
+OF MATTERS TO A VOTE OF SECURITY HOLDERS 
+No matters were submitted
+to a vote of our security holders during the three months ended March 31,
+2009. 
+PART II 
+ITEM 5. MARKET
+FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
+PURCHASES OF EQUITY SECURITIES 
+Market Information and Holders 
+Our common stock is
+traded on the NYSE Amex under the symbol “ITI.” 
+The following table sets forth, for the periods indicated, the high and
+low sales prices for our common stock as reported by NYSE Amex: 
+High 
+Low 
+Fiscal 2009 
+Quarter Ended June 30, 2008 
+$ 
+2.98 
+$ 
+2.14 
+Quarter Ended September 30, 2008 
+2.45 
+1.65 
+Quarter Ended December 31, 2008 
+1.83 
+1.16 
+Quarter Ended March 31, 2009 
+1.50 
+0.98 
+Fiscal 2008 
+Quarter Ended June 30, 2007 
+$ 
+2.66 
+$ 
+2.11 
+Quarter Ended September 30, 2007 
+2.50 
+2.00 
+Quarter Ended December 31, 2007 
+4.20 
+2.18 
+Quarter Ended March 31, 2008 
+4.06 
+1.94 
+On June 5, 2009, the
+last reported sales price of our common stock on the NYSE Amex was $1.39. As of June 5, 2009, we had
+425 holders of record of our common stock according to information furnished
+by our transfer agent. 
+Dividend Policy 
+We have never paid or
+declared cash dividends on our common stock, and have no current plans to pay
+such dividends in the foreseeable future. We currently intend to retain any
+earnings for working capital and general corporate purposes. The payment of any
+future dividends will be at the discretion of our Board of Directors and will
+depend upon a number of factors, including, but not limited to, future
+earnings, the success of our business, our capital requirements, our general
+financial condition and future prospects, general business conditions, the
+consent of our lender and such other factors as the Board of Directors may deem
+relevant. 
+14 
+Table of Contents 
+ITEM 6. SELECTED
+FINANCIAL DATA 
+As a smaller reporting
+company, we are not required to make any disclosure pursuant to this Item 6. 
+ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS
+OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+You should read the following discussion and analysis in
+conjunction with our Consolidated Financial Statements and related Notes
+thereto included in Part IV, Item 15 of this report and the “Risk Factors”
+section in Item 1A, as well as other cautionary statements and risks
+described elsewhere in this report, before deciding to purchase, hold or sell
+our common stock. 
+Overview 
+We are a leader in the
+traffic management market focused on the development and application of
+advanced technologies that reduce traffic congestion and improve the safety of
+surface transportation systems infrastructure. As an added benefit, our
+products and services minimize the environmental impact of traffic congestion.
+By combining outdoor image processing, traffic engineering and information
+technology, we offer a broad range of ITS and driver safety solutions to
+customers worldwide. 
+We currently operate in
+three reportable segments: Roadway Sensors, Vehicle Sensors, and Transportation
+Systems. The Roadway Sensors segment includes our Vantage and VersiCam vehicle
+detection systems for traffic intersection control, incident detection and
+certain highway traffic data collection applications. The Vehicle Sensors
+segment includes our AutoVue LDW system and is comprised of all activities
+related to vehicle safety. The Transportation Systems segment includes
+transportation engineering and consulting services, and the development of
+transportation management and traveler information systems for the ITS
+industry. 
+Our Roadway Sensors
+segment product line uses advanced image processing technology to capture and
+analyze video images through sophisticated algorithms, enabling vehicle
+detection and transmission of both video images and data using a wide range of
+communication technologies. Our Vantage
+video detection systems detect vehicle presence, count, speed, occupancy, and
+other traffic data used in traffic management systems. This gives traffic managers the ability to
+mitigate roadway congestion by modifying traffic signal timing or detecting
+incidents quickly. VersiCam, our
+integrated camera and processor video detection system, is a cost-efficient
+video detection system for smaller intersections that require only a few
+detection points. Vantage video
+detection systems have been deployed by hundreds of agencies and are currently
+sold through a network of independent dealers in the United States, Asia, Latin
+America, Europe and the Middle East. 
+Our Vehicle Sensors
+segment addresses the leading cause of roadway fatalities: rear-end, lane change, and roadway departure
+accidents. According to the National
+Highway Traffic Safety Administration, these three crash types result in about
+27,500 of the U.S.’s 42,000 annual traffic fatalities and contribute to a
+considerable economic loss due to injuries, property damage, and decreased
+productivity. 
+Our Vehicle Sensors
+segment developed the world’s first production LDW system and offers a proven
+system that is available as an OEM and aftermarket option on heavy trucks
+worldwide and as an option in passenger cars. 
+Our LDW products utilize video detection images to detect when a vehicle
+begins to drift toward an unintended lane change. When this occurs, the unit automatically
+emits a distinctive rumble strip or other audible warning sound, alerting the
+driver to make a correction. To date, we
+have sold approximately 69,000 LDW systems into the heavy truck market in
+Europe, North America and Asia. Our LDW
+systems are currently qualified as an option on certain heavy trucks, including
+Mercedes-Benz, MAN, Iveco, DAF, Scania, Freightliner and FUSO, as well as
+Neoplan and MAN luxury bus and coach lines. In North America, our LDW systems
+are sold primarily to truck fleets, and to date, 74 U.S. heavy truck fleets
+have selected our LDW systems, with a combined fleet size estimated at 58,000
+vehicles. Additionally, we have licensed
+our LDW technology to our strategic partner, Valeo, resulting in sales to date
+of approximately 69,000 LDW systems for passenger cars. 
+In addition to our LDW
+systems, we expanded our Vehicle Sensors portfolio in August 2008 with
+newly developed technologies such as radar based Forward Collision Warning and
+Blind Spot Warning systems for the North American truck market. We also introduced Safety Direct in March 2008,
+which is a system that reports real-time driver performance data captured by
+our LDW system and that has the ability to relay this information directly to
+fleet operators through integration with the truck’s existing fleet
+communications system. We offer the FCW
+and BSW features through the resale of Delphi’s radar based systems, for which
+we are the exclusive North American dealer, while Safety Direct was internally
+developed. These new products, together with our LDW products, combine to
+create a broad suite of active safety driver assistance features that help to
+reduce the number of motor vehicle crashes and the severity of crash-related
+injuries. 
+15 
+Table of Contents 
+Our Transportation
+Systems segment includes transportation engineering and consulting services
+focused on the planning, design, development and implementation of
+software-based systems that integrate sensors, video surveillance, computers,
+and advanced communications equipment to enable public agencies to monitor,
+control, and direct traffic flow, assist in the quick dispatch of emergency
+crews and distribute real-time information about traffic conditions. Our
+services include planning, design, and implementation of surface transportation
+infrastructure systems. We perform analysis and study goods movement,
+commercial vehicle operations, travel demand forecasting, and systems engineering,
+and identify mitigation measures to reduce traffic congestion. These services
+and systems are primarily sold to local, state, and national transportation
+agencies in the United States. Our Transportation Systems segment is largely
+dependent upon governmental funding and budgetary issues. The Federal Highway
+Bill that was passed in August 2005 provided for a significant increase in
+transportation funding. We believe the recent expansion of our Transportation
+Systems segment was due in part to the passage of the Federal Highway Bill,
+combined with increased transportation funds available at state and local
+agencies throughout the country. The
+2005 Federal Highway Bill is set to expire in September 2009. At this point in time, the impact on future
+contract revenues as a result of the recently introduced federal stimulus
+package and any potential delays in the passage of future transportation bills
+cannot be determined. 
+During Fiscal 2009, we
+introduced certain products including VersiCam, EdgeConnect and Safety Direct.
+We also completed the acquisition of certain assets of Hamilton Signal
+including the Abacus system for an aggregate purchase price of approximately
+$518,000. This acquisition should afford us with the opportunity to provide our
+customers with traffic and incident detection data from our installed base of
+surveillance cameras. 
+Critical
+Accounting Policies and Estimates 
+Management’s Discussion
+and Analysis of Financial Condition and Results of Operations is based on our
+consolidated financial statements included herein, which have been prepared in
+accordance with generally accepted accounting principles in the United States (“GAAP”).
+The preparation of these financial statements requires management to make
+estimates and assumptions that affect the reported amounts of assets and
+liabilities and related disclosures of contingent assets and liabilities at the
+date of the financial statements and the reported amounts of revenues and
+expenses during the reporting period. On an ongoing basis, we evaluate these
+estimates and assumptions, including those related to the collectibility of
+accounts receivable, the valuation of inventories, the recoverability of
+long-lived assets and goodwill, the realizability of deferred tax assets,
+accounting for stock-based compensation, the valuation of equity instruments,
+warranty reserves and other contingencies. We base these estimates on
+historical experience and on various other factors that we believe to be
+reasonable under the circumstances, the results of which form the basis for
+making judgments about the carrying values of assets and liabilities that are
+not readily apparent from other sources. These estimates and assumptions by
+their nature involve risks and uncertainties, and may prove to be inaccurate.
+In the event that any of our estimates or assumptions are inaccurate in any
+material respect, it could have a material adverse effect on our reported
+amounts of assets and liabilities at the date of the financial statements and
+the reported amounts of revenues and expenses during the reporting period. 
+The following critical
+accounting policies affect our more significant judgments and estimates used in
+the preparation of our consolidated financial statements. 
+Revenue Recognition. We record product revenues and related
+costs of sales upon transfer of title, which is generally upon shipment or, if
+required, upon acceptance by the customer, provided that we believe
+collectibility of the net sales amount is reasonably assured. Accordingly, at the date revenue is recognized,
+the significant uncertainties concerning the sale have been resolved. 
+Contract revenues are
+derived primarily from long-term contracts with governmental agencies. Contract
+revenues include costs incurred plus a portion of estimated fees or profits
+determined using the percentage of completion method of accounting based on the
+relationship of costs incurred to total estimated costs. Any anticipated losses
+on contracts are charged to earnings when identified. Changes in job
+performance and estimated profitability, including those arising from contract
+penalty provisions and final contract settlements, may result in revisions to
+recognized costs and revenues and are recognized in the period in which the
+revisions are determined. Profit incentives are included in revenue when their
+realization is reasonably assured. 
+In addition to
+product and contract revenues, we derive revenue from technology access fees,
+the provision of specific non-recurring contract engineering services to our
+strategic partner, Valeo, related to our LDW systems, and royalties earned on
+unit sales of our LDW systems by Valeo to the passenger car market. Technology
+access fee revenues are recognized evenly over the period in which they are
+earned. Non-recurring contract engineering revenues are recognized in the
+period in which the related services are performed. Royalty revenues are
+recorded based on unit sales of our products by Valeo and are recognized in the
+period in which such sales occur. Technology access fee revenues, non-recurring
+contract engineering revenues and royalty revenues are included in net sales. 
+Revenues from follow-on
+service and support, for which we generally charge separately, are recorded in
+the period in which the services are performed. 
+Accounts Receivable. We estimate the collectibility of
+customer receivables on an ongoing basis by periodically reviewing invoices
+outstanding greater than a certain period of time. We record reserves for
+receivables deemed to be at risk for collection as well as a general reserve
+based on our historical collections experience. A considerable amount of
+judgment is required in assessing 
+16 
+Table of Contents 
+the ultimate realization of trade receivables,
+including the current credit-worthiness of each customer. If the financial
+condition of our customers deteriorates, resulting in an impairment of their
+ability to make required payments, additional allowances may be required that
+could adversely affect our operating results. 
+Inventory. Inventories consist of finished goods,
+work-in-process and raw materials and are stated at the lower of cost or
+market. We provide reserves for potentially excess and obsolete inventory. In
+assessing the ultimate realization of inventories, we make judgments as to
+future demand requirements and compare that with the current or committed
+inventory levels. Reserves are established for inventory levels that exceed
+anticipated future demand. It is possible that reserves over and above those
+already established may be required in the future if market conditions for our
+products deteriorate. 
+Goodwill. Goodwill is tested for impairment
+annually in our fourth fiscal quarter at the reporting unit level unless a
+change in circumstances indicates that more frequent impairment analysis is
+required. Impairment, if any, is measured based on the estimated fair value of
+the reporting units with the recorded goodwill. Fair value is determined by
+using the income approach methodology of valuation which utilizes discounted
+cash flows taking into consideration the market approach. The estimated fair
+value of our reporting units also includes a control premium, which is the
+amount that a buyer is willing to pay over the current market price of a
+company as indicated by the traded price per share (i.e., market
+capitalization), in order to acquire a controlling interest. Significant
+management judgment is required in the forecasts of future operating results
+that are used in the discounted cash flow method of valuation. In estimating
+future cash flows, we generally use the financial assumptions in our current
+budget and our current strategic plan, subject to modification as considered
+necessary, including sales and expense growth rates and the discount rates we
+estimate to represent our cost of funds. It is possible, however, that the
+plans and estimates used may be incorrect. If our actual results, or the plans
+and estimates used in future impairment analyses, are lower than the original
+estimates used to assess the recoverability of goodwill, we could incur
+impairment charges. 
+Warranty. We generally provide a one to three year
+warranty from the original invoice date on all products, materials and
+workmanship. Defective products are either repaired or replaced, at our option,
+upon meeting certain criteria. We accrue a provision for the estimated costs
+that may be incurred for product warranties relating to a product as a
+component of cost of sales at the time revenue for that product is recognized.
+The accrued warranty provision is included within accrued expenses on the
+accompanying consolidated balance sheets. Should our actual experience of
+warranty returns be higher than anticipated, additional warranty reserves may
+be required, which may adversely affect our operating results. 
+Income Taxes. On a quarterly basis, we assess the
+likelihood that our deferred tax asset balance will be recovered from future
+taxable income. Realization of deferred tax assets (such as net operating loss
+carryforwards) is dependent on future taxable earnings and is therefore
+uncertain. To the extent we believe that recovery is not likely, we establish a
+valuation allowance to reduce our deferred tax assets to amounts that we
+believe are more likely than not to be realized, which increases our income tax
+expense in the period such determination is made. 
+On an interim basis, we
+estimate what our anticipated annual effective tax rate will be and record a
+quarterly income tax provision in accordance with this anticipated rate. As the
+fiscal year progresses, we refine our estimates based upon actual events and
+earnings during the year. This estimation process can result in significant
+changes to our expected effective tax rate. When this occurs, we adjust the
+income tax provision during the quarter in which the change in estimate occurs
+so that the year-to-date provision reflects the expected annual rate. The
+changes described in the preceding sentence and adjustments to our valuation
+allowance may create fluctuations in our overall effective tax rate from
+quarter to quarter. 
+Effective April 1,
+2007, we adopted the provisions of Financial Accounting Standards Board (“FASB”)
+Interpretation No. 48, Accounting for Uncertainty
+in Income Taxes – an Interpretation of FASB Statement No. 109 (“FIN
+48”), which applies to all tax positions accounted for under Statement of
+Financial Accounting Standards (“SFAS”) No. 109, Accounting
+for Income Taxes (“SFAS 109”). 
+FIN 48 clarifies the accounting for uncertainty in income taxes by
+establishing minimum standards for the recognition and measurement of tax
+positions taken or expected to be taken in a tax return. Under the requirements
+of FIN 48, we must review all of our tax positions and make a determination as
+to whether our position is more-likely-than-not to be sustained upon
+examination by regulatory authorities. If a tax position meets the
+more-likely-than-not standard, then the related tax benefit is measured based
+on a cumulative probability analysis of the amount that is more-likely-than-not
+to be realized upon ultimate settlement or disposition of the underlying issue. 
+The application of tax
+laws and regulations is subject to legal and factual interpretation, judgment
+and uncertainty. Tax laws and regulations themselves are subject to change as a
+result of changes in fiscal policy, changes in legislation, the evolution of
+regulations and court rulings. Therefore, the actual liability for U.S. or
+foreign taxes may be materially different from our estimates, which could
+result in the need to record additional tax liabilities or potentially reverse
+previously recorded tax liabilities. 
+Stock-Based
+Compensation . We adopted SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS 123R”), effective April 1,
+2006. SFAS 123R requires all stock-based
+payments, including grants of employee stock options, to be recognized in the
+statement of operations as an expense, based on their grant date fair values
+with such fair values amortized over the requisite service 
+17 
+Table of
+Contents 
+period. We elected to utilize the modified
+prospective method for the transition to SFAS 123R. Under the modified
+prospective method, SFAS 123R applies to all awards granted or modified after
+the date of adoption. In addition, under the modified prospective method,
+compensation expense will be recognized for all stock-based compensation awards
+granted prior to but not yet vested as of April 1, 2006, based on
+grant-date fair values estimated in accordance with the original provisions of
+SFAS 123. 
+In implementing SFAS
+123R, we have used the Black-Scholes-Merton (“BSM”) option-pricing formula to
+estimate the fair value of stock-based awards granted subsequent to April 1,
+2006. While this model meets the
+requirements of SFAS 123R, the estimated fair values generated by it may
+not be indicative of the actual fair values of our stock-based awards as it
+does not consider certain factors important to those awards to employees, such
+as continued employment and periodic vesting requirements as well as limited
+transferability. Our assumptions under
+the BSM formula include the following: (i) expected
+volatilities are based on the historical volatility of our stock price, (ii) the
+expected life of options is derived based on the historical life of our
+options, (iii) the risk-free rate for periods within the expected life of
+the option is based on the U.S. Treasury interest rates in effect at the time
+of grant and (iv) the dividend yield assumption is based on our history
+and expectation of dividend payouts. 
+Additionally, SFAS 123 did not require the estimation of forfeitures in
+the calculation of stock compensation expense; however, SFAS 123R does require
+such estimation and upon adoption of SFAS 123R, we changed our methodology to
+include an estimate of forfeitures. 
+Future stock-based compensation expense in any particular quarter or
+year could be affected by changes in our assumptions, changes in market
+conditions, or to the extent that we grant additional stock-based awards.
+Additionally, if there are any modifications or cancellations of the underlying
+unvested stock-based awards, we may be required to accelerate, increase or
+cancel any remaining unearned stock-based compensation expense. 
+Results
+of Operations 
+The following table sets
+forth certain statement of operations data as a percentage of total net sales
+and contract revenues for the periods indicated. The following table should be
+read in conjunction with Management’s Discussion and Analysis of Financial
+Condition and Results of Operations. 
+Year Ended
+March 31, 
+2009 
+2008 
+2007 
+Net sales and contract revenues: 
+Net sales 
+55.4 
+% 
+61.9 
+% 
+62.2 
+% 
+Contract revenues 
+44.6 
+38.1 
+37.8 
+Total net sales and contract revenues 
+100.0 
+% 
+100.0 
+% 
+100.0 
+% 
+Costs of net sales and contract revenues: 
+Cost of net sales 
+29.3 
+31.5 
+34.0 
+Cost of contract revenues 
+30.4 
+25.1 
+24.8 
+Gross profit 
+40.3 
+43.4 
+41.2 
+Operating expenses: 
+Selling, general and administrative 
+26.0 
+26.5 
+27.5 
+Research and development 
+5.8 
+5.5 
+6.9 
+Amortization of intangible assets 
+0.2 
+0.2 
+0.3 
+Total operating expenses 
+32.0 
+32.2 
+34.6 
+Operating income 
+8.2 
+11.2 
+6.6 
+Non-operating income (expense): 
+Other income (expense), net 
+0.2 
+0.4 
+(1.1 
+) 
+Interest expense, net 
+(0.9 
+) 
+(2.0 
+) 
+(2.7 
+) 
+Income before income taxes 
+7.5 
+9.6 
+2.7 
+Income tax benefit 
+7.6 
+9.1 
+2.3 
+Net income 
+15.1 
+% 
+18.7 
+% 
+5.0 
+% 
+Analysis
+of Fiscal 2009, Fiscal 2008 and Fiscal 2007 Results of Operations 
+Net
+Sales and Contract Revenues . Net sales are comprised of
+product sales from our Roadway Sensors and Vehicle Sensors segments, as well as
+technology access fees, contract engineering revenue and royalty revenue generated
+from our Vehicle Sensors segment. Contract revenues consist entirely of
+Transportation Systems contract revenues, which are generated from systems
+integration and ITS consulting services primarily with federal, state, county
+and municipal agencies. 
+18 
+Table of Contents 
+The following
+tables present details of our net sales and contract revenues for Fiscal 2009
+compared to Fiscal 2008 and Fiscal 2008 compared to Fiscal 2007, respectively: 
+Fiscal 
+Fiscal 
+Increase 
+% 
+2009 
+2008 
+(Decrease) 
+Change 
+(In
+thousands, except percentages) 
+Roadway
+sensors 
+$ 
+27,197 
+$ 
+28,452 
+(1,255 
+) 
+(4.4 
+)% 
+Vehicle
+sensors 
+11,230 
+11,874 
+(644 
+) 
+(5.4 
+) 
+Net
+sales 
+38,427 
+40,326 
+(1,899 
+) 
+(4.7 
+) 
+Contract
+revenues 
+30,932 
+24,837 
+6,095 
+24.5 
+Total
+net sales and contract revenues 
+$ 
+69,359 
+$ 
+65,163 
+$ 
+4,196 
+6.4 
+Fiscal 
+Fiscal 
+% 
+2008 
+2007 
+Increase 
+Change 
+(In thousands, except percentages) 
+Roadway
+sensors 
+$ 
+28,452 
+$ 
+27,261 
+1,191 
+4.4 
+% 
+Vehicle
+sensors 
+11,874 
+8,987 
+2,887 
+32.1 
+Net
+sales 
+40,326 
+36,248 
+4,078 
+11.3 
+Contract
+revenues 
+24,837 
+22,049 
+2,788 
+12.6 
+Total
+net sales and contract revenues 
+$ 
+65,163 
+$ 
+58,297 
+$ 
+6,866 
+11.8 
+We currently have
+a diverse customer base with no individual customer representing greater than
+10% of our total net sales and contract revenues for Fiscal 2009 or 2008, and
+one customer representing approximately 12.4% of our net sales and contract
+revenues in Fiscal 2007. 
+Roadway Sensors 
+The majority of Roadway
+Sensors net sales were derived from sales within North America. The decrease in Roadway Sensors net sales in
+Fiscal 2009 as compared to Fiscal 2008 was mainly due to reduced and delayed
+spending on infrastructure projects as a result of the decline in commercial
+and residential construction, as well as local government budgetary pressures.
+We expect the above factors, among others, may continue to adversely impact our
+Roadway Sensors net sales for at least the next few fiscal quarters. The
+increase in net sales in Fiscal 2008 as compared to Fiscal 2007 primarily
+reflects the continued adoption of video vehicle detection technology, such as
+the technology offered by our Vantage line of products, both domestically and internationally. 
+Vehicle Sensors 
+The largest element of
+Vehicle Sensors net sales was sales of our LDW systems to the heavy truck
+market, which aggregated approximately $9.9 million in Fiscal 2009, $10.0
+million in Fiscal 2008 and $6.4 million in Fiscal 2007. Vehicle Sensors net sales decreased slightly
+in Fiscal 2009 as compared to Fiscal 2008 primarily due to a significant
+slowdown in overall LDW unit shipments to each of our key markets in the fourth
+quarter of Fiscal 2009. The increase in Fiscal 2008 net sales of Vehicle
+Sensors products, as compared to Fiscal 2007, was primarily a result of
+increased unit sales of our LDW systems to European and Asian OEMs. 
+Recently, we have
+experienced softness in our LDW unit sales to the North American truck market
+and to our European and Asian OEM customers, which was driven largely by the
+general slowdown in the U.S. and worldwide credit markets and continued
+weakness in the overall global economy. 
+We expect declining LDW unit sales for the first quarter of Fiscal 2010
+due to these and other macroeconomic conditions. Additionally, Vehicle Sensors unit sales in
+Fiscal 2010 and beyond could also be adversely impacted by slower than expected
+adoption rates of our LDW system by European and Asian OEMs and North American
+heavy truck fleets, as well as potential additional OEM volume discounts
+resulting from increased price competition as new competitors have entered this
+market. Additionally, certain recent
+environmental regulations in Europe and North America have substantially
+increased the cost of new commercial trucks, which could impact future truck
+sales volumes and, ultimately, unit sales of our LDW systems. 
+Also included in Vehicle
+Sensors net sales are revenues from contract engineering services, technology access
+fees and royalty revenues in the passenger car market that are derived from our
+strategic relationship with Valeo, which aggregated approximately $1.3 million,
+$1.9 million and $2.6 million in Fiscal 2009, Fiscal 2008 and Fiscal 2007,
+respectively. The total revenues for
+Fiscal 2007 included certain technology access fee revenue of $500,000 that did
+not recur in either Fiscal 2008 or 2009. 
+Royalty revenues from Valeo for sales of our LDW systems for the passenger
+car market were relatively insignificant in Fiscal 2009, Fiscal 2008 and Fiscal
+2007. Our LDW systems are now offered as
+an option on three Infiniti models. 
+While Valeo is promoting our LDW systems to other passenger car OEMs, we
+cannot assure you that Valeo will be successful in these efforts. 
+19 
+Table
+of Contents 
+Contract Revenues 
+Contract revenues are
+primarily dependent upon the continued availability of funding at both the
+state and federal levels from the various departments of transportation. The Fiscal 2009 increase in contract revenues
+was largely a result of our increased sales and marketing activity across the
+U.S., resulting in certain significant new contracts that were awarded to us
+during the current fiscal year. Certain of these new contracts contained a
+higher than usual amount of sub-consulting content, which was primarily
+concentrated in our contract revenues in the fourth quarter of Fiscal 2009. The
+Fiscal 2008 increase in contract revenues was largely due to increased funding
+at the federal, state and local levels throughout the country, as well as new
+contract awards. At the end of Fiscal
+2009, our Transportation Systems segment’s staff levels approximated those of
+the prior year-end; however, in response to the growth we have experienced in
+our Transportation Systems segment over the last several years, we increased
+this segment’s staff by 21% in Fiscal 2008 and 16% in Fiscal 2007. We believe the ability of our Transportation
+Systems business to grow and successfully win and service new contracts will be
+highly dependent upon our continued success in recruiting and retaining
+qualified personnel. All of our contract
+revenues are derived from work performed in North America under a broad range
+of fixed price and cost plus fixed fee contracts. 
+Gross
+Profit . The following tables present details of our gross
+profit for Fiscal 2009 compared to Fiscal 2008 and Fiscal 2008 compared to
+Fiscal 2007, respectively: 
+Fiscal 
+Fiscal 
+% 
+2009 
+2008 
+Decrease 
+Change 
+(In thousands, except percentages) 
+Total
+gross profit 
+$ 
+27,919 
+$ 
+28,297 
+$ 
+(378 
+) 
+(1.3 
+)% 
+Total
+gross profit as a % of total net sales and contract revenues 
+40.3 
+% 
+43.4 
+% 
+Gross
+profit as a % of net sales 
+47.1 
+% 
+49.2 
+% 
+Gross
+profit as a % of contract revenues 
+31.8 
+% 
+34.1 
+% 
+Fiscal 
+Fiscal 
+% 
+2008 
+2007 
+Increase 
+Change 
+(In thousands, except percentages) 
+Total
+gross profit 
+$ 
+28,297 
+$ 
+24,008 
+$ 
+4,289 
+17.9 
+% 
+Total
+gross profit as a % of total net sales and contract revenues 
+43.4 
+% 
+41.2 
+% 
+Gross
+profit as a % of net sales 
+49.2 
+% 
+45.3 
+% 
+Gross
+profit as a % of contract revenues 
+34.1 
+% 
+34.4 
+% 
+The decrease in gross
+profit as a percent of net sales in Fiscal 2009 as compared to Fiscal 2008 was
+primarily a result of decreased gross profit in Roadway Sensors and was
+primarily driven by our customer mix. Roadway Sensors net sales were weighted
+more toward dealer than direct sales in Fiscal 2009. We generally enjoy higher
+gross margins on direct sales as compared to dealer and aftermarket sales. The increase in gross profit as a percentage
+of net sales in Fiscal 2008 as compared to Fiscal 2007 was a result of a
+favorable sales mix in terms of both geography and product mix, as well as
+improved production efficiencies. Gross
+profit as a percentage of net sales also improved in Fiscal 2008 through the
+expansion of our Vehicle Sensors customer base, which helped mitigate the
+impact of lower contractual pricing to our largest European customer. Gross profit as a percentage of net sales can
+fluctuate in any specific quarter or year based on, among other factors,
+customer and product mix, competitive pricing requirements, product warranty
+costs and provisions for excess and obsolete inventories, as well as possible
+shifts of engineering resources from development activities to sustaining
+activities, which we record as cost of goods sold. 
+We recognize contract
+revenues and related gross profit using percentage of completion contract
+accounting, and the underlying mix of contract activity affects the related
+gross profit recognized in any given period. The decreases in gross profit as a
+percent of contract revenues in Fiscal 2009 compared to Fiscal 2008 and Fiscal
+2008 compared to Fiscal 2007 primarily reflect a contract mix weighted more
+toward lower margin contracts in those periods. 
+Lower margin contracts generally have a higher proportion of
+sub-consulting revenues associated with them. We experienced an abnormally high
+level of sub-consulting content related to certain new contracts during the
+fourth quarter of Fiscal 2009, which contributed both to the overall increase
+in contract revenues, as described above, as well as the decrease in our gross
+profit. For the first quarter of Fiscal 2010, we do not expect similar levels
+of sub-consulting content; however, due to the variability and timing of our
+contracts, we may experience higher than usual sub-consulting content in future
+periods. 
+20 
+Table of Contents 
+Selling,
+General and Administrative Expense 
+The following table
+presents selling, general and administrative expense for Fiscal 2009 and 2008: 
+Fiscal 2009 
+Fiscal 2008 
+% of Net 
+% of Net 
+Sales and 
+Sales and 
+Contract 
+Contract 
+Increase 
+% 
+Amount 
+Revenues 
+Amount 
+Revenues 
+(Decrease) 
+Change 
+(In thousands, except percentages) 
+Salary
+and personnel-related 
+$ 
+11,949 
+17.2 
+% 
+$ 
+10,916 
+16.8 
+% 
+$ 
+1,033 
+9.5 
+% 
+Facilities,
+insurance and supplies 
+2,378 
+3.4 
+2,254 
+3.5 
+124 
+5.5 
+Professional
+and outside services 
+1,302 
+1.9 
+1,734 
+2.7 
+(432 
+) 
+(24.9 
+) 
+Travel
+and conferences 
+1,563 
+2.3 
+1,323 
+2.0 
+240 
+18.1 
+Other 
+843 
+1.2 
+1,062 
+1.6 
+(219 
+) 
+(20.6 
+) 
+Selling,
+general and administrative 
+$ 
+18,035 
+26.0 
+% 
+$ 
+17,289 
+26.5 
+% 
+$ 
+746 
+4.3 
+The overall increase in
+selling, general and administrative expenses in Fiscal 2009 was primarily
+driven by higher selling expenses in our Transportation Systems segment as a
+result of a shift in certain of our labor resources from project-related
+activities to sales and marketing efforts, aimed at capturing additional
+contract backlog. This resulted in an increase in this segment’s sales and
+marketing expenses to $2.8 million for Fiscal 2009 compared to $2.0 million for
+Fiscal 2008. Our professional and outside services expenses decreased in Fiscal
+2009 primarily due to our efforts to conserve costs and scale back our usage of
+certain outside and professional services, as well as various efficiencies
+gained in our internal control assessment and other financial reporting
+obligations in the current year. In Fiscal 2010, we will be subject to the requirement
+that our independent registered public accounting firm provide an attestation
+on the effectiveness of our internal control over financial reporting, for
+which we expect additional increases in our general and administrative
+expenses. 
+The following table
+presents selling, general and administrative expense for Fiscal 2008 and 2007: 
+Fiscal 2008 
+Fiscal 2007 
+% of Net 
+% of Net 
+Sales and 
+Sales and 
+Contract 
+Contract 
+Increase 
+% 
+Amount 
+Revenues 
+Amount 
+Revenues 
+(Decrease) 
+Change 
+(In thousands, except percentages) 
+Salary and
+personnel-related 
+$ 
+10,916 
+16.8 
+% 
+$ 
+10,024 
+17.2 
+% 
+$ 
+892 
+8.9 
+% 
+Facilities, insurance
+and supplies 
+2,254 
+3.5 
+2,101 
+3.6 
+153 
+7.3 
+Professional and
+outside services 
+1,734 
+2.7 
+1,764 
+3.0 
+(30 
+) 
+(1.7 
+) 
+Travel and conferences 
+1,323 
+2.0 
+1,250 
+2.1 
+73 
+5.8 
+Other 
+1,062 
+1.6 
+864 
+1.5 
+198 
+22.9 
+Selling, general and
+administrative 
+$ 
+17,289 
+26.5 
+% 
+$ 
+16,003 
+27.5 
+% 
+$ 
+1,286 
+8.0 
+The increase in selling,
+general and administrative expense in Fiscal 2008 compared to Fiscal 2007 was
+largely attributable to higher commissions and selling expenses driven by sales
+growth in our Roadway Sensors segment, as well as general and administrative
+expenses incurred related to our efforts to comply with the internal control
+assessment and reporting requirements. 
+21 
+Table of Contents 
+Research
+and Development Expense 
+The following table
+presents research and development expense for Fiscal 2009 and 2008: 
+Fiscal 2009 
+Fiscal 2008 
+% of Net 
+% of Net 
+Sales and 
+Sales and 
+Contract 
+Contract 
+Increase 
+% 
+Amount 
+Revenues 
+Amount 
+Revenues 
+(Decrease) 
+Change 
+(In thousands, except percentages) 
+Salary and
+personnel-related 
+$ 
+2,748 
+4.0 
+% 
+$ 
+2,294 
+3.5 
+% 
+$ 
+454 
+19.8 
+% 
+Facilties, development
+and supplies 
+1,018 
+1.5 
+1,019 
+1.6 
+(1 
+) 
+(0.1 
+) 
+Other 
+264 
+0.4 
+253 
+0.4 
+11 
+4.3 
+Research and
+development 
+$ 
+4,030 
+5.8 
+% 
+$ 
+3,566 
+5.5 
+% 
+$ 
+464 
+13.0 
+The increase in research
+and development expense in Fiscal 2009 compared to Fiscal 2008 was primarily
+due to increased research and development activities in Roadway Sensors aimed
+at accelerating the time to market of certain new products. We believe research
+and development activities are crucial to our ability to continue to be a
+leader in our markets. 
+The following table
+presents research and development expense for Fiscal 2008 and 2007: 
+Fiscal 2008 
+Fiscal 2007 
+% of Net 
+% of Net 
+Sales and 
+Sales and 
+Contract 
+Contract 
+Increase 
+% 
+Amount 
+Revenues 
+Amount 
+Revenues 
+(Decrease) 
+Change 
+(In thousands, except percentages) 
+Salary and
+personnel-related 
+$ 
+2,294 
+3.5 
+% 
+$ 
+2,265 
+3.9 
+% 
+$ 
+29 
+1.3 
+% 
+Facilties, development
+and supplies 
+1,019 
+1.6 
+1,474 
+2.5 
+(455 
+) 
+(30.9 
+) 
+Other 
+253 
+0.4 
+291 
+0.5 
+(38 
+) 
+(13.1 
+) 
+Research and
+development 
+$ 
+3,566 
+5.5 
+% 
+$ 
+4,030 
+6.9 
+% 
+$ 
+(464 
+) 
+(11.5 
+) 
+The decrease in research
+and development expense in Fiscal 2008 compared to Fiscal 2007 was primarily
+due to reduced research and development activities in Vehicle Sensors as many
+of our significant truck OEM customers now have production LDW units that only
+require minimal further development and the majority of our passenger car
+research and development efforts are funded by our strategic partner,
+Valeo. This decreased spending was
+partially offset by increased research and development spending in Roadway
+Sensors. 
+For competitive reasons,
+we closely guard the confidentiality of specific development projects. 
+Other
+Income (Expense), Net 
+The following table
+presents other income (expense), net for Fiscal 2009, 2008 and 2007: 
+Year Ended March 31, 
+2009 
+2008 
+2007 
+(In thousands) 
+Net
+gain on early extinguishment of debt 
+$ 
+50 
+$ 
+224 
+$ 
+— 
+Settlement
+of lawsuits 
+— 
+— 
+(635 
+) 
+Other 
+66 
+28 
+(18 
+) 
+Other
+income (expense), net 
+$ 
+116 
+$ 
+252 
+$ 
+(653 
+) 
+Other
+income, net in Fiscal 2009 includes the net gain of $50,000 we recognized in
+connection with the early retirement of $7.0 million of convertible debentures,
+as well as certain net foreign currency gains and other miscellaneous income.
+Other income, net in Fiscal 2008 primarily reflects the net gain of $224,000 we
+recognized in connection with the early retirement of $2.1 million of
+convertible debentures. See Note 3 of Notes to Consolidated Financial
+Statements for additional discussion regarding the early retirement of our
+convertible debentures. Other expense,
+net in Fiscal 2007 primarily reflects $635,000 of expense recorded in
+connection with the settlement of litigation in July 2006, which is
+discussed further in Note 5 of Notes to Consolidated Financial Statements. 
+22 
+Table
+of Contents 
+Interest
+Expense, Net 
+The following table
+presents interest expense, net for Fiscal 2009, 2008 and 2007: 
+Year Ended March 31, 
+2009 
+2008 
+2007 
+(In thousands) 
+Interest
+expense 
+$ 
+(651 
+) 
+$ 
+(1,285 
+) 
+$ 
+(1,601 
+) 
+Interest
+income 
+5 
+1 
+1 
+Interest
+expense, net 
+$ 
+(646 
+) 
+$ 
+(1,284 
+) 
+$ 
+(1,600 
+) 
+Interest
+expense, net decreased 49.7% in Fiscal 2009 compared to Fiscal 2008 and decreased
+19.8% in Fiscal 2008 compared to Fiscal 2007 primarily due to our lower overall
+level of borrowings, lower interest rates and also as a result of the early
+retirement of certain of our convertible debentures, as discussed above. 
+Income
+Taxes 
+The following table
+presents our benefit for income taxes for Fiscal 2009, 2008 and 2007: 
+Year Ended March 31, 
+2009 
+2008 
+2007 
+(In thousands, except percentages) 
+Income
+tax benefit 
+$ 
+5,297 
+$ 
+5,900 
+$ 
+1,343 
+Effective
+tax rate 
+(102.3 
+)% 
+(94.2 
+)% 
+(85.3 
+)% 
+The income tax benefits
+recorded in Fiscal 2009, Fiscal 2008 and Fiscal 2007 were primarily the result
+of a decrease in the valuation allowance recorded against our deferred tax
+assets as a result of changes in estimates of the future realizability of these
+assets. As we update our estimates in
+future periods, adjustments to our deferred tax asset and valuation allowance
+may be necessary. We anticipate this will cause our future overall effective
+tax rate in any given period to fluctuate from prior effective tax rates and
+statutory tax rates. We utilize the asset and liability method of accounting
+for income taxes as set forth in SFAS No. 109, Accounting
+for Income Taxes . We record
+net deferred tax assets to the extent that we believe these assets will more
+likely than not be realized. In making such determination, we consider all
+available positive and negative evidence, including, but not limited to,
+scheduled reversals of deferred tax liabilities, projected future taxable
+income, tax planning strategies and recent financial performance. 
+At March 31, 2009,
+we had $40.8 million of federal net operating loss carryforwards and
+$18.4 million of state net operating loss carryforwards that begin to
+expire in 2019 and 2013, respectively. Due to changes in stock ownership, our
+federal net operating loss carryforwards are subject to a Section 382
+limitation estimated at approximately $7.8 million annually which can be
+utilized to offset federal consolidated taxable income. Although the impact cannot be precisely
+determined, we believe that our net operating loss carryforwards will cause us
+to have future income tax payments and income tax expense that are
+substantially lower than the income tax liability and income tax expense
+calculated using statutory tax rates. 
+Liquidity
+and Capital Resources 
+Cash Flows 
+We have historically financed our operations with a
+combination of cash flows from operations, borrowings under credit facilities
+and the sale of equity securities. We currently rely on cash flows from
+operations and the availability of borrowings on a line of credit facility to
+fund our operations, which we believe to be sufficient to fund our operations
+for at least the next twelve months. At March 31,
+2009, we had $20.6 million in working capital, which included no borrowings on
+our $12.0 million line of credit and $6.4 million in cash and cash equivalents,
+as compared to working capital of $14.9 million at March 31, 2008. 
+23 
+Table of Contents 
+The following table summarizes our cash flows for
+Fiscal 2009, 2008 and 2007: 
+Year Ended March 31, 
+2009 
+2008 
+2007 
+(In thousands) 
+Net cash provided by (used in): 
+Operating
+activities 
+$ 
+6,390 
+$ 
+7,579 
+(2,049 
+) 
+Investing
+activities 
+(795 
+) 
+(739 
+) 
+(488 
+) 
+Financing
+activities 
+413 
+(6,454 
+) 
+2,441 
+Net
+increase (decrease) in cash and cash equivalents 
+$ 
+6,008 
+$ 
+386 
+$ 
+(96 
+) 
+Operating Activities. 
+Cash provided by our operations in Fiscal 2009 was primarily the result
+of our Fiscal 2009 net income of $10.5 million adjusted for certain non-cash
+items within the statement of operations, primarily adjustments to our deferred
+tax balances and depreciation and stock-based compensation expenses. 
+Our net accounts receivable decreased approximately
+$700,000 from March 31, 2008 to March 31, 2009 due primarily to lower
+product sales in the fourth quarter of Fiscal 2009 as compared to the
+corresponding quarter in the prior year. Additionally, our net costs and
+estimated earnings in excess of billings decreased approximately $1.5 million
+over the same period, primarily as a result of improved timeliness of billings
+in our Transportation Systems segment during Fiscal 2009. If, in the longer
+term, our net sales and contract revenues increase, it is likely that both our
+accounts receivable and net costs and estimated earnings in excess of billings
+balances will also increase. Our accounts receivable could also increase if customers
+delay their payments or if we grant extended payment terms to customers, both
+of which are more likely to occur during challenging economic times when our
+customers may face issues gaining sufficient credit on a timely basis. 
+Inventories increased approximately $1.5 million from March 31,
+2008 to March 31, 2009 due primarily to a decrease in product sales, the
+introduction of new products by our Roadway Sensors segment and the acquisition
+of certain components because they have been discontinued by the manufacturer.
+In the future, our inventory levels are likely to continue to be determined
+based upon, among other factors, the level of purchase orders we receive, the
+stage at which our products are in their respective product life cycles, and
+competitive situations in the marketplace. We attempt to balance such
+considerations against risk of obsolescence or potentially excess inventory
+levels. 
+Cash provided by our operations in Fiscal 2008 was
+primarily a result of our Fiscal 2008 net income of $12.2 million and $1.6
+million in net cash provided by changes in operating assets and liabilities,
+partially offset by approximately $6.2 million in net non-cash items within the
+statement of operations. During Fiscal
+2007, cash used in operations was primarily a result of investments in
+inventory due to sales growth and longer lead times in procuring certain
+components, and an increased level of net costs and estimated earnings in
+excess of billings due to sales growth and the timing of invoicing on contracts
+in our Transportation Systems segment. 
+These were partially offset by our Fiscal 2007 net income of $2.9
+million. 
+Investing Activities. Investing activities for Fiscal 2009, Fiscal 2008 and
+Fiscal 2007 each consisted primarily of purchases of certain property and
+equipment. 
+Financing Activities. Net cash provided by financing activities in Fiscal
+2009 was the result of $900,000 in cash inflows from the exercise of stock
+options to purchase our common stock, partially offset by net payments on our
+borrowings of $500,000. Net cash used in financing activities in Fiscal 2008
+was the result of net payments on our borrowings of $8.0 million, partially
+offset by cash inflows of $1.5 million from the exercise of outstanding stock
+options and warrants to purchase our common stock. During Fiscal 2007, net cash provided by
+financing activities was the result of cash inflows of $3.6 million from the
+exercise of outstanding stock options and warrants to purchase our common stock,
+of which approximately $2.0 million was raised through the exercise of
+outstanding warrants to purchase an aggregate of 1,250,000 shares of our common
+stock. These cash inflows were partially offset by net payments on our
+borrowings of $1.2 million. 
+Borrowings 
+The following table
+summarizes our borrowings and long-term debt: 
+March 31, 
+2009 
+(In thousands) 
+Convertible
+debentures, net 
+$ 
+750 
+Bank
+term note 
+6,543 
+$ 
+7,293 
+24 
+Table of Contents 
+Prior to October 16,
+2008, we had a credit facility with a bank that provided for line of credit
+borrowings of up to $10.0 million. Under this credit facility, we could borrow
+against our eligible accounts receivable and eligible inventory, as defined in
+the credit agreement. Interest on borrowed amounts under the line of credit was
+payable monthly at the current stated prime rate plus 1.00%. Additionally, we
+were obligated to pay an unused line fee of 0.25% per annum applied to the
+amount by which the maximum credit amount exceeded the average daily principal
+balance during the preceding month. The credit facility required $2,000 in
+monthly collateral management fees and included an early termination fee equal
+to 2% of the total facility during the first year of the agreement and 1% of
+the total facility in the second year of the agreement. The credit facility was
+secured by substantially all of our assets. 
+This credit facility expired on October 15, 2008. 
+Effective October 16,
+2008, we entered into a new $19.5 million credit facility with a different bank
+(California Bank & Trust) which replaced our existing credit
+facility. This new credit facility
+provides for a two-year revolving line of credit with borrowings of up to $12.0
+million and a $7.5 million 48-month term note (discussed below). Interest on borrowed amounts under the
+revolving line of credit will be payable monthly at a rate equal to the current
+stated prime rate up to the current stated prime rate plus 0.50%, depending on
+aggregate deposit balances maintained at the bank in relation to the total loan
+commitment under the credit facility (3.75% at March 31, 2009). We are obligated to pay an unused line fee of
+0.25% per annum applied to the average unused portion of the revolving line of
+credit during the preceding month. The
+revolving line of credit does not contain any early termination fees and is
+secured by substantially all of our assets. 
+As of March 31, 2009, no amounts were borrowed under the revolving
+line of credit portion of the facility. 
+Additionally, as
+part of this new credit facility and in connection with the early retirement of
+$7.0 million of our convertible debentures, as of March 31, 2009 we have
+borrowed $6.5 million under the $7.5 million 48-month term note to retire such
+outstanding debentures. In May 2009, we borrowed an additional $750,000
+under the term note to pay off the remaining convertible debentures of the same
+amount. Principal payments under this term note are required to be repaid in 48
+monthly installments commencing on June 1, 2009. Interest on the term note
+will be payable monthly at a rate equal to the current stated prime rate plus
+0.50% up to the current stated prime rate plus 1.00%, depending on aggregate
+deposit balances maintained at the bank in relation to the total loan
+commitment under the credit facility. In
+October 2008, we paid an upfront loan commitment fee of $28,000 in
+connection with the term note portion of the credit facility. The term note contains no early termination
+fees and, along with our revolving line of credit discussed above, is secured
+by substantially all of our assets. 
+In connection with
+our credit facility and loan agreement with California Bank & Trust,
+we are also required to comply with certain quarterly financial covenants.
+These include achieving certain ratios for working capital and debt service, as
+well as maintaining a level of profitability, all of which are further defined in
+the agreement. While we are currently in compliance with all financial
+covenants and expect to maintain compliance for the foreseeable future, we
+cannot assure that we will not violate one or more covenants in the future. If
+we were to be in violation of covenants under this agreement, our lender could
+choose to accelerate payment on all outstanding loan balances. In this event,
+there can be no assurances that we would be able to quickly obtain equivalent
+or suitable replacement financing. If we were not able to secure alternative
+sources of financing, such acceleration would have a material adverse impact on
+our financial condition. 
+On February 4,
+2009 we entered into an Amended and Restated Loan and Security Agreement with
+California Bank & Trust which supersedes the agreements entered into
+on October 16, 2008 in their entirety. The October 16, 2008 documents
+were amended and restated to clarify certain ambiguities and remove
+non-applicable language. No
+modifications were made to any significant provisions related to the overall
+amount of the credit facility, interest rate calculations, or any financial or
+non-financial covenant. 
+Off
+Balance Sheet Arrangements 
+In May 2004, we issued
+subordinated convertible debentures in an aggregate original principal amount
+of $10.1 million. These debentures were due in full on May 19, 2009
+and were convertible into shares of our common stock at a conversion price of
+$3.61 per share. At March 31, 2009, convertible debentures in an aggregate
+principal amount of $750,000 remained outstanding, and were subsequently paid
+off in full on May 19, 2009. Because these debentures were conventionally
+convertible, we have not separately accounted for the conversion feature and,
+accordingly, no separate amounts are presented in our consolidated financial
+statements in connection with this conversion feature. 
+At March 31, 2009,
+outstanding warrants to purchase an aggregate of 246,250 shares of our
+common stock at an exercise price of $3.25 per share are callable by us if the
+market price of our common stock trades for 20 consecutive days at a price
+equal to or greater than two times the exercise price of the warrants.
+Outstanding w arrants to purchase an aggregate of 75,000 shares of
+our common stock at an exercise price of $5.00 per share are callable by us if
+the market price of our common stock trades for 20 consecutive days at a price
+equal to or greater than one and a half times the exercise price of the
+warrants. 
+25 
+Table
+of Contents 
+In connection with the
+issuance of warrants to purchase 246,250 shares of our common stock at $3.25
+per share, we are a party to a registration rights agreement that contains
+provisions under which we could be subjected to liquidated damages should we
+fail to maintain effective registration statements for the shares of common
+stock issuable upon exercise of certain underlying warrants. These warrants
+have been accounted for within equity in our consolidated balance sheets in
+accordance with EITF Issue No. 00-19, Accounting for Derivative
+Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own
+Stock , and, accordingly, no liabilities have been recorded in connection
+therewith. As of the date of this filing, no liquidated damages are payable
+under the provisions of the registration rights agreement associated with these
+warrants. 
+Recent
+Accounting Pronouncements 
+In September 2006, the FASB issued SFAS No. 157,
+Fair Value Measurements , (“SFAS 157”),
+which defines fair value, establishes a framework for measuring fair value, and
+expands disclosure about fair value measurements. SFAS 157 does not require any
+new fair value measurements; rather it specifies valuation methods to be
+applied when fair value measurements are required under existing or future
+accounting pronouncements. SFAS 157 is effective for fiscal years beginning
+after November 15, 2007 and interim periods within those fiscal years. In February 2008,
+the FASB issued FASB Staff Position (“FSP”) 157-2, Effective
+Date of FASB Statement No. 157 (“FSP 157-2”), which delays the
+effective date of SFAS 157 for non-financial assets and liabilities to fiscal
+years beginning after November 15, 2008. Generally, SFAS 157 will be
+applied prospectively. With respect to financial assets and liabilities, we
+adopted SFAS 157 in the first quarter of Fiscal 2009. There was no material
+impact on our consolidated financial statements. We are currently evaluating
+the impact of SFAS 157 and FSP 157-2 with respect to our non-financial assets
+and liabilities and expect to adopt SFAS 157 and FSP 157-2 with respect to
+these assets and liabilities in the first quarter of Fiscal 2010. 
+In December 2007,
+the FASB issued SFAS No. 141R, Business Combinations 
+(“SFAS 141R”). SFAS 141R establishes principles and requirements for
+how the acquirer of a business recognizes and measures in its financial
+statements the identifiable assets acquired, the liabilities assumed, and any
+noncontrolling interest in the acquiree. The statement also provides guidance
+for recognizing and measuring the goodwill acquired in the business combination
+and determines what information to disclose to enable users of financial
+statements to evaluate the nature and financial effects of the business
+combination. Additionally, in April 2009, the FASB issued FSP 141R-1, Accounting for Assets Acquired and Liabilities Assumed in a Business
+Combination that Arise from Contingencies (“FSP 141R-1”), which
+amends SFAS 141R to require that assets acquired and liabilities assumed in a
+business combination that are from contingencies be recognized in accordance
+with FAS 157 if the fair value can be determined during the measurement
+period. SFAS 141R and FSP 141R-1
+are both effective for financial statements issued for fiscal years beginning
+after December 15, 2008. The nature and magnitude of the specific effects
+of adopting SFAS 141R and FSP 141R-1 will depend upon the nature, terms and
+size of any acquisitions we may consummate after the effective date of our
+adoption of SFAS 141R in the first quarter of Fiscal 2010. 
+In April 2008, the
+FASB issued FSP No. 142-3, Determination of the
+Useful Life of Intangible Assets (“FSP 142-3”), which amends the
+guidance about estimating the useful lives of recognized intangible assets and
+requires additional disclosures related to renewing or extending the terms of
+recognized intangible assets under SFAS 142. FSP 142-3 is effective for
+financial statements issued for fiscal years, and interim periods within those
+fiscal years, beginning after December 15, 2008. We currently do not
+expect the adoption of FSP 142-3 will have a material impact on our
+consolidated financial statements. 
+In May 2008, the
+FASB issued SFAS No. 162, The
+Hierarchy of Generally Accepted Accounting Principles (“SFAS 162”). SFAS 162
+identifies the sources of accounting principles to be used in the preparation
+of financial statements of nongovernmental entities that are presented in
+conformity with GAAP. SFAS 162 is effective 60 days following
+the Securities and Exchange Commission approval of the Public Company
+Accounting Oversight Board amendments to AU Section 411, The Meaning of Present Fairly in Conformity with
+Generally Accepted Accounting Principles. We currently adhere to the
+hierarchy of GAAP as presented in SFAS 162, and adoption is not expected
+to have a material impact on our consolidated financial statements. 
+In May 2008, the
+FASB issued FSP APB 14-1, Accounting for Convertible
+Debt Instruments That May Be Settled in Cash upon Conversion (Including
+Partial Cash Settlement) (“FSP APB 14-1”). FSP APB 14-1 clarifies
+that convertible debt instruments that may be settled in cash upon either
+mandatory or optional conversion (including partial cash settlement) are not
+addressed by paragraph 12 of APB Opinion No. 14, Accounting
+for Convertible Debt and Debt Issued with Stock Purchase Warrants .
+Additionally, FSP APB 14-1 specifies that issuers of such instruments should
+separately account for the liability and equity components in a manner that
+will reflect the entity’s nonconvertible debt borrowing rate when interest cost
+is recognized in subsequent periods. FSP APB 14-1 is effective for financial
+statements issued for fiscal years beginning after December 15, 2008, and
+interim periods within those fiscal years, and must be applied on a
+retrospective basis. We plan to adopt FSP APB 14-1 in the first fiscal quarter
+of Fiscal 2010 and are currently evaluating the impact to our consolidated
+financial statements. 
+In June 2008, the
+FASB issued Emerging Issues Task Force (“EITF”) Issue No. 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to
+an Entity’s Own Stock (“EITF 07-5”). EITF 07-5 clarifies how to
+determine whether certain instruments or features were indexed to an entity’s
+own stock under EITF Issue No. 01-6, The Meaning of “Indexed to
+a Company’s Own Stock,” (“EITF 01-6”), and provides guidance to
+determine what accounting literature may apply to a particular equity linked
+instrument or feature. EITF 07-5 will become effective for financial statements
+issued for fiscal years beginning after December 15, 2008, and interim
+periods within those fiscal years, and must be applied to all instruments
+outstanding on the date of adoption. We plan to adopt EITF 07-5 in the first
+quarter of Fiscal 2010 and are currently evaluating the impact to our
+consolidated financial statements. 
+26 
+Table
+of Contents 
+In May 2009, the
+FASB issued SFAS No. 165, Subsequent Events 
+(“SFAS 165”). SFAS 165 provides authoritative accounting literature related to
+evaluating subsequent events that was previously addressed only in the auditing
+literature, and is largely similar to the current guidance in the auditing
+literature with some exceptions that are not intended to result in significant
+changes in practice. SFAS 165 defines subsequent events and also requires the
+disclosure of the date through which an entity has evaluated subsequent events
+and the basis for that date. SFAS 165 is effective on a prospective basis for
+interim or annual financial periods ending after June 15, 2009. We plan to
+adopt SFAS 165 in the first quarter of Fiscal 2010 and do not expect it to have
+a material impact on our consolidated financial statements. 
+Seasonality 
+We have historically
+experienced seasonality, particularly with respect to our Roadway Sensors net
+sales in the third and fourth fiscal quarters due to a reduction in road
+construction and repairs during the winter months due to inclement weather
+conditions. 
+ITEM 7A. QUANTITATIVE AND
+QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
+Our exposure to interest
+rate risk is limited to our line of credit and our bank term note. Our line of
+credit bears interest based on the prevailing prime rate (3.25% at March 31,
+2009) plus 0% to 1.0%. We do not believe
+that a 10% increase in the interest rate on our line of credit or term note
+(from 3.25% to 4.68%) would have a material impact on our financial position,
+operating results or cash flows. In addition, we believe that the carrying
+value of our outstanding debt under our credit facility approximates fair
+value. 
+ITEM 8. FINANCIAL STATEMENTS AND
+SUPPLEMENTARY DATA 
+The financial statements
+and supplementary data required by Regulation S-X are included in Part IV,
+Item 15 of this report. 
+ITEM 9. CHANGES IN AND
+DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+None. 
+ITEM 9A. CONTROLS AND PROCEDURES 
+(a) Evaluation of disclosure controls and
+procedures. In accordance with Rule 13a-15(b) of
+the Securities Exchange Act of 1934, as of the end of the period covered by
+this Annual Report on Form 10-K, management evaluated, with the
+participation of the our President and Chief Executive Officer and the Chief
+Financial Officer, the effectiveness of the design and operation of our
+disclosure controls and procedures (as defined in Rule 13a-15(e) under
+the Exchange Act). Based upon their evaluation of these disclosure controls and
+procedures, the President and Chief Executive Officer and the Chief Financial
+Officer have concluded that our disclosure controls and procedures were
+effective as of the date of such evaluation in ensuring that information
+required to be disclosed in our Exchange Act reports is (1) recorded,
+processed, summarized and reported in a timely manner, and (2) accumulated
+and communicated to management, including the Company’s President and Chief
+Executive Officer and the Chief Financial Officer, as appropriate, to allow
+timely decisions regarding required disclosure. 
+(b) 
+Changes in internal control. There was no
+change in our internal control over financial reporting that occurred during
+the period covered by this Annual Report on Form 10-K that has materially
+affected, or is reasonably likely to materially affect, our internal control
+over financial reporting. 
+Inherent Limitations on Internal
+Control 
+A control system, no
+matter how well conceived and operated, can provide only reasonable, not
+absolute, assurance that the objectives of the control system are met. Further,
+the benefits of controls must be considered relative to their costs. Because of
+the inherent limitations in all control systems, no evaluation of controls can
+provide absolute assurance that all control issues and instances of management
+override or improper acts, if any, have been detected. These inherent
+limitations include the realities that judgments in decision making can be
+faulty, and that breakdowns can occur because of simple errors. Additionally,
+controls can be circumvented by the individual acts of some persons, by
+collusion of two or more people, or by management override of the control. The
+design of any system of controls is also based in part upon certain assumptions
+about the likelihood of future events, and there can be no assurance that any
+design will succeed in achieving its stated goals under all potential future
+conditions. Because of the inherent limitations in a cost-effective control
+system, misstatements due to management override, error or improper acts may
+occur and not be detected. Any resulting misstatement or loss may have an
+adverse and material effect on our business, financial condition and results of
+operations. 
+27 
+Table of Contents 
+Management’s Report on Internal
+Control Over Financial Reporting 
+Our management is
+responsible for establishing and maintaining adequate internal control over
+financial reporting. Our internal control system was designed to provide
+reasonable assurance to management and the board of directors regarding the
+effectiveness of our internal control processes over the preparation and fair
+presentation of published financial statements. 
+We have assessed the
+effectiveness of our internal controls over financial reporting as of March 31,
+2009. In making this assessment, we used the criteria set forth by the
+Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in
+Internal Control—Integrated Framework. Based on our assessment, we believe
+that, as of March 31, 2009, our internal control over financial reporting
+is effective based on those criteria. 
+This annual report does
+not include an attestation report of our independent registered public
+accounting firm regarding internal control over financial reporting. Management’s
+report was not subject to attestation by our independent registered public
+accounting firm pursuant to the rules of the Securities and Exchange
+Commission that permit us to provide only management’s report in this annual
+report. 
+ITEM 9B . OTHER INFORMATION 
+In May 2009,
+we entered into a separation agreement with Francis Memole, the former Senior
+Vice President and General Manager of our Vehicle Sensors segment, related to
+his termination of employment with Iteris, Inc. Pursuant to this
+agreement, we have agreed to pay four and one half months of severance to Mr. Memole
+for an aggregate severance amount of approximately $72,000, in exchange for Mr. Memole’s
+broad release of claims against us and our affiliates. In addition, we
+have agreed to pay 65% of Mr. Memole’s COBRA premiums until December 31,
+2009 pursuant to the American Recovery and Reinvestment Act, as well as
+the balance of his first month’s COBRA premium. 
+PART III 
+ITEM 10. DIRECTORS, EXECUTIVE
+OFFICERS AND CORPORATE GOVERNANCE 
+(a) Identification of Directors. The
+information under the caption “Election of Directors,” appearing in our proxy
+statement for the 2009 Annual Meeting of Stockholders, is incorporated herein
+by reference. 
+(b) Identification of Executive Officers. The
+information under the caption “Executive Compensation and Other Information -
+Executive Officers,” appearing in our proxy statement for the 2009 Annual
+Meeting of Stockholders, is incorporated herein by reference. 
+(c) Compliance with Section 16(a) of the
+Exchange Act. The information under the caption “Section 16(a) Beneficial
+Ownership Reporting Compliance” appearing in our proxy statement for the 2009
+Annual Meeting of Stockholders is incorporated herein by reference. 
+(d) Corporate Governance .
+The information under the caption “Corporate Governance,” appearing in our
+proxy statement for the 2009 Annual Meeting of Stockholders, is incorporated
+herein by reference. 
+(e) Audit Committee .
+The information under the caption “Board Meetings and Committees — Audit
+Committee,” appearing in our proxy statement for the 2009 Annual Meeting of
+Stockholders, is incorporated herein by reference. 
+ITEM 11. EXECUTIVE COMPENSATION 
+The information under the
+caption “Executive Compensation and Other Information,” appearing in our proxy
+statement for the 2009 Annual Meeting of Stockholders, is incorporated herein
+by reference. 
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN
+BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+The information under the
+captions “Equity Compensation Plans” and “Principal Stockholders and Common
+Stock Ownership of Certain Beneficial Owners and Management,” appearing in our
+proxy statement for the 2009 Annual Meeting of Stockholders, is incorporated
+herein by reference. 
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
+DIRECTOR INDEPENDENCE 
+The information under the
+captions “Corporate Governance — Director Independence” and “Certain
+Transactions,” appearing in our proxy statement for the 2009 Annual Meeting of
+Stockholders, is incorporated herein by reference. 
+28 
+Table of Contents 
+ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES 
+The information under the
+caption “Fees Paid to Independent Registered Public Accounting Firm,” appearing
+in our proxy statement for the 2009 Annual Meeting of Stockholders, is
+incorporated herein by reference. 
+29 
+Table of Contents 
+PART IV 
+ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 
+(a) Documents
+filed as part of this report: 
+1. Financial Statements. The following financial statements of
+Iteris, Inc. are included in a separate section of this Annual Report
+on Form 10-K commencing on the pages referenced below: 
+Report of
+Independent Registered Public Accounting Firm 
+34 
+Consolidated Balance
+Sheets as of March 31, 2009 and 2008 
+35 
+Consolidated
+Statements of Operations for the years ended March 31, 2009, 2008 and
+2007 
+36 
+Consolidated
+Statements of Stockholders’ Equity and Comprehensive Income for the years
+ended March 31, 2009, 2008 and 2007 
+37 
+Consolidated
+Statements of Cash Flows for the years ended March 31, 2009, 2008 and
+2007 
+38 
+Notes to Consolidated Financial Statements 
+39 
+2. Exhibits . 
+The exhibits listed on the accompanying index to
+exhibits immediately following the financial statements are filed as part of,
+or hereby incorporated by reference into, this report. 
+30 
+Table of Contents 
+SIGNATURES 
+Pursuant to the
+requirements of Section 13 or 15(d) of the Securities Exchange Act of
+1934, the registrant has duly caused this report to be signed on its behalf by
+the undersigned, thereunto duly authorized. 
+Dated: June 11,
+2009 
+ITERIS, INC. 
+(Registrant) 
+By 
+/S/ ABBAS MOHADDES 
+Abbas Mohaddes 
+Chief Executive Officer 
+(Principal Executive
+Officer) 
+31 
+Table
+of Contents 
+POWER OF
+ATTORNEY 
+We, the undersigned
+officers and directors of Iteris, Inc., do hereby constitute and appoint
+James S. Miele and Abbas Mohaddes, and each of them, our true and lawful
+attorneys-in-fact and agents, each with full power of substitution and
+resubstitution, for him and in his name, place and stead, in any and all
+capacities, to sign any and all amendments to this report, and to file the
+same, with exhibits thereto, and other documents in connection therewith, with
+the Securities and Exchange Commission, granting unto said attorneys-in-fact
+and agents, and each of them, full power and authority to do and perform each
+and every act and thing requisite or necessary to be done in and about the
+premises, as fully to all intents and purposes as he might or could do in
+person, hereby, ratifying and confirming all that each of said
+attorneys-in-fact and agents, or his substitute or substitutes, may lawfully do
+or cause to be done by virtue hereof. 
+Pursuant to the
+requirements of the Securities Exchange Act of 1934, this report has been
+signed below by the following persons on behalf of the registrant in the
+capacities and on the dates indicated: 
+Signature 
+Title 
+Date 
+/s/ ABBAS
+MOHADDES 
+Director, President and Chief Executive Officer 
+June 11, 2009 
+Abbas Mohaddes 
+(principal executive officer) 
+/s/ JAMES S.
+MIELE 
+Chief Financial Officer 
+June 11, 2009 
+James S. Miele 
+(principal financial and accounting officer) 
+/s/ GREGORY A.
+MINER 
+Chairman of the Board 
+June 11, 2009 
+Gregory A. Miner 
+/s/ RICHARD CHAR 
+Director 
+June 11, 2009 
+Richard Char 
+/s/ KEVIN C.
+DALY 
+Director 
+June 11, 2009 
+Kevin C. Daly,
+Ph.D. 
+/s/ JOHN
+SEAZHOLTZ 
+Director 
+June 11, 2009 
+John Seazholtz 
+/s/ JOEL SLUTZKY 
+Director 
+June 11, 2009 
+Joel Slutzky 
+/s/ THOMAS L.
+THOMAS 
+Director 
+June 11, 2009 
+Thomas L. Thomas 
+32 
+Table of Contents 
+Iteris, Inc. 
+Index to Consolidated Financial Statements 
+Report
+of Independent Registered Public Accounting Firm 
+34 
+Consolidated
+Balance Sheets as of March 31, 2009 and 2008 
+35 
+Consolidated
+Statements of Operations for the years ended March 31, 2009, 2008 and
+2007 
+36 
+Consolidated
+Statements of Stockholders’ Equity and Comprehensive Income for the years
+ended March 31, 2009, 2008 and 2007 
+37 
+Consolidated
+Statements of Cash Flows for the years ended March 31, 2009, 2008 and
+2007 
+38 
+Notes to Consolidated Financial Statements 
+39 
+33 
+Table
+of Contents 
+Report
+of Independent Registered Public Accounting Firm 
+To the Board of Directors
+and Stockholders 
+Iteris, Inc. 
+We have audited the accompanying consolidated balance
+sheets of Iteris, Inc. as of March 31, 2009 and 2008, and the related
+consolidated statements of operations, stockholders’ equity and comprehensive
+income, and cash flows for each of the three years in the period ended March 31,
+2009. These financial statements are the
+responsibility of the Company’s management. 
+Our responsibility is to express an opinion on these financial
+statements based on our audits. 
+We conducted our audits in accordance with the
+standards of the Public Company Accounting Oversight Board (United
+States). Those standards require that we
+plan and perform the audit to obtain reasonable assurance about whether the
+financial statements are free of material misstatement. An audit includes examining, on a test basis,
+evidence supporting the amounts and disclosures in the financial
+statements. An audit also includes
+assessing the accounting principles used and significant estimates made by
+management, as well as evaluating the overall financial statement
+presentation. We believe that our audits
+provide a reasonable basis for our opinion. 
+In our opinion, the consolidated financial statements
+referred to above present fairly, in all material respects, the financial
+position of Iteris, Inc. as of March 31, 2009 and 2008, and the
+results of its operations and its cash flows for each of the three years in the
+period ended March 31, 2009, in conformity with U.S. generally accepted
+accounting principles. 
+As discussed in Note 1 to the consolidated financial
+statements, effective April 1, 2007 the Company changed its method of
+accounting for uncertainty in income taxes. 
+We were not engaged to examine management’s assessment
+of the effectiveness of Iteris, Inc.’s internal control over financial
+reporting as of March 31, 2009, included in the accompanying Management’s
+Report on Internal Control Over Financial Reporting and, accordingly, we do not
+express an opinion thereon. 
+/s/ McGladrey &
+Pullen, LLP 
+Irvine, California 
+June 10, 2009 
+34 
+Table of
+Contents 
+Iteris, Inc. 
+Consolidated Balance Sheets 
+(In thousands, except par value) 
+March 31, 
+2009 
+2008 
+Assets 
+Current
+assets: 
+Cash
+and cash equivalents 
+$ 
+6,372 
+$ 
+421 
+Trade
+accounts receivable, net of allowance for doubtful accounts of $534 and
+$1,020 at March 31, 2009 and 2008, respectively 
+12,448 
+13,108 
+Costs
+in excess of billings on uncompleted contracts 
+4,217 
+5,351 
+Inventories 
+5,681 
+4,226 
+Deferred
+income taxes 
+4,241 
+2,541 
+Prepaid
+expenses and other current assets 
+272 
+371 
+Total
+current assets 
+33,231 
+26,018 
+Property
+and equipment: 
+Leasehold
+improvements 
+1,930 
+1,915 
+Equipment 
+8,136 
+7,356 
+Accumulated
+depreciation 
+(6,822 
+) 
+(5,804 
+) 
+3,244 
+3,467 
+Deferred
+income taxes 
+11,505 
+7,807 
+Intangible
+assets, net 
+110 
+257 
+Goodwill 
+27,774 
+27,774 
+Other
+assets 
+202 
+322 
+Total
+assets 
+$ 
+76,066 
+$ 
+65,645 
+Liabilities and stockholders’ equity 
+Current
+liabilities: 
+Trade
+accounts payable 
+$ 
+4,228 
+$ 
+3,902 
+Accrued
+payroll and related expenses 
+3,188 
+3,825 
+Accrued
+liabilities 
+1,662 
+1,973 
+Billings
+in excess of costs and estimated earnings on uncompleted contracts 
+1,534 
+1,126 
+Current
+portion of long-term debt 
+2,019 
+244 
+Total
+current liabilities 
+12,631 
+11,070 
+Deferred
+rent 
+1,686 
+1,956 
+Unrecognized
+tax benefits 
+1,117 
+1,381 
+Other
+non-current liabilities 
+— 
+461 
+Long-term
+debt 
+5,274 
+7,566 
+Total
+liabilities 
+20,708 
+22,434 
+Commitments
+and contingencies 
+Stockholders’
+equity: 
+Preferred
+stock, $1.00 par value: 
+Authorized
+shares - 2,000 
+Issued
+and outstanding shares - none 
+— 
+— 
+Common
+stock. $0.10 par value: 
+Authorized
+shares - 70,000 at March 31, 2009 and 2008 
+Issued
+and outstanding shares - 34,205 at March 31, 2009 and 33,420 at
+March 31, 2008 
+3,420 
+3,342 
+Additional
+paid-in capital 
+136,997 
+135,516 
+Common
+stock held in trust 
+(31 
+) 
+(202 
+) 
+Accumulated
+deficit 
+(85,025 
+) 
+(95,499 
+) 
+Accumulated
+other comprehensive income (loss) 
+(3 
+) 
+54 
+Total
+stockholders’ equity 
+55,358 
+43,211 
+Total
+liabilities and stockholders’ equity 
+$ 
+76,066 
+$ 
+65,645 
+See accompanying
+notes. 
+35 
+Table of Contents 
+Iteris, Inc. 
+Consolidated Statements of Operations 
+(In thousands, except per share amounts) 
+Year Ended March 31, 
+2009 
+2008 
+2007 
+Net
+sales and contract revenues: 
+Net
+sales 
+$ 
+38,427 
+$ 
+40,326 
+$ 
+36,248 
+Contract
+revenues 
+30,932 
+24,837 
+22,049 
+Total
+net sales and contract revenues 
+69,359 
+65,163 
+58,297 
+Costs
+of net sales and contract revenues: 
+Cost
+of net sales(a) 
+20,346 
+20,499 
+19,829 
+Cost
+of contract revenues(a) 
+21,094 
+16,367 
+14,460 
+Gross
+profit 
+27,919 
+28,297 
+24,008 
+Operating
+expenses: 
+Selling,
+general and administrative(a) 
+18,035 
+17,289 
+16,003 
+Research
+and development(a) 
+4,030 
+3,566 
+4,030 
+Amortization
+of intangible assets 
+147 
+147 
+147 
+Total
+operating expenses 
+22,212 
+21,002 
+20,180 
+Operating
+income 
+5,707 
+7,295 
+3,828 
+Non-operating
+income (expense): 
+Other
+income (expense), net 
+116 
+252 
+(653 
+) 
+Interest
+expense, net 
+(646 
+) 
+(1,284 
+) 
+(1,600 
+) 
+Income
+before income taxes 
+5,177 
+6,263 
+1,575 
+Income
+tax benefit 
+5,297 
+5,900 
+1,343 
+Net
+income 
+$ 
+10,474 
+$ 
+12,163 
+$ 
+2,918 
+Earnings
+per share: 
+Basic 
+$ 
+0.31 
+$ 
+0.37 
+$ 
+0.10 
+Diluted 
+$ 
+0.30 
+$ 
+0.35 
+$ 
+0.09 
+Weighted-average
+shares outstanding: 
+Basic 
+33,964 
+32,723 
+29,698 
+Diluted 
+34,638 
+34,713 
+33,348 
+(a) 
+Includes stock-based compensation
+expense as follows: 
+Cost
+of net sales 
+$ 
+9 
+$ 
+3 
+$ 
+13 
+Cost
+of contract revenues 
+38 
+14 
+60 
+Selling,
+general and administrative 
+297 
+266 
+195 
+Research
+and development 
+20 
+7 
+20 
+Total
+stock-based compensation expense 
+$ 
+364 
+$ 
+290 
+$ 
+288 
+See accompanying
+notes. 
+36 
+Table of Contents 
+Iteris, Inc. 
+Consolidated Statements of Stockholders’ Equity and
+Comprehensive Income 
+(In thousands) 
+Common 
+Stock Shares 
+Amount 
+Additional 
+Paid-In 
+Capital 
+Common 
+Stock Held 
+in Trust 
+Notes 
+Receivable 
+From 
+Employees 
+Accumulated 
+Deficit 
+Accumulated Other 
+Comprehensive 
+Income (Loss) 
+Total Stockholder’s 
+Equity 
+Balance
+at March 31, 2006 
+27,432 
+$ 
+2,743 
+$ 
+126,664 
+$ 
+(374 
+) 
+$ 
+(49 
+) 
+$ 
+(110,356 
+) 
+$ 
+7 
+$ 
+18,635 
+Warrant
+exercises 
+1,706 
+170 
+2,265 
+— 
+— 
+— 
+— 
+2,435 
+Stock
+option exercises 
+1,374 
+138 
+982 
+— 
+— 
+— 
+— 
+1,120 
+Issuance
+of warrants 
+— 
+— 
+22 
+— 
+— 
+— 
+— 
+22 
+Stock-based
+compensation 
+— 
+— 
+288 
+— 
+— 
+— 
+— 
+288 
+Issuance
+of common stock in connection with legal settlement 
+89 
+9 
+204 
+— 
+— 
+— 
+— 
+213 
+Repayment
+of notes receivable from employees 
+— 
+— 
+— 
+— 
+44 
+— 
+— 
+44 
+Components of
+comprehensive income: 
+Foreign
+currency translation 
+— 
+— 
+— 
+— 
+— 
+— 
+12 
+12 
+Net
+income 
+— 
+— 
+— 
+— 
+— 
+2,918 
+— 
+2,918 
+Comprehensive
+income 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+2,930 
+Balance
+at March 31, 2007 
+30,601 
+3,060 
+130,425 
+(374 
+) 
+(5 
+) 
+(107,438 
+) 
+19 
+25,687 
+Conversion
+of redeemable common stock to common stock 
+1,219 
+122 
+3,292 
+— 
+— 
+— 
+— 
+3,414 
+Warrant
+exercises 
+85 
+9 
+113 
+— 
+— 
+— 
+— 
+122 
+Stock
+option exercises 
+1,515 
+151 
+1,223 
+— 
+— 
+— 
+— 
+1,374 
+Stock-based
+compensation 
+— 
+— 
+290 
+— 
+— 
+— 
+— 
+290 
+Issuance
+of shares held in trust 
+— 
+— 
+178 
+172 
+— 
+— 
+— 
+350 
+Write-off
+of notes receivable from employees 
+— 
+— 
+(5 
+) 
+— 
+5 
+— 
+— 
+— 
+Cumulative
+effect of adoption of FIN 48 
+— 
+— 
+— 
+— 
+— 
+(224 
+) 
+— 
+(224 
+) 
+Components
+of comprehensive income: 
+Foreign
+currency translation 
+— 
+— 
+— 
+— 
+— 
+— 
+35 
+35 
+Net
+income 
+— 
+— 
+— 
+— 
+— 
+12,163 
+— 
+12,163 
+Comprehensive
+income 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+12,198 
+Balance
+at March 31, 2008 
+33,420 
+3,342 
+135,516 
+(202 
+) 
+— 
+(95,499 
+) 
+54 
+43,211 
+Stock
+option exercises 
+785 
+78 
+861 
+— 
+— 
+— 
+— 
+939 
+Stock-based
+compensation 
+— 
+— 
+364 
+— 
+— 
+— 
+— 
+364 
+Issuance
+of shares held in trust 
+— 
+— 
+256 
+171 
+— 
+— 
+— 
+427 
+Components
+of comprehensive income: 
+Foreign
+currency translation 
+— 
+— 
+— 
+— 
+— 
+— 
+(57 
+) 
+(57 
+) 
+Net
+income 
+— 
+— 
+— 
+— 
+— 
+10,474 
+— 
+10,474 
+Comprehensive
+income 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+10,417 
+Balance
+at March 31, 2009 
+34,205 
+$ 
+3,420 
+$ 
+136,997 
+$ 
+(31 
+) 
+$ 
+— 
+$ 
+(85,025 
+) 
+$ 
+(3 
+) 
+$ 
+55,358 
+See accompanying
+notes. 
+37 
+Table of Contents 
+Iteris, Inc. 
+Consolidated Statements of Cash Flows 
+(In thousands) 
+Year Ended March 31, 
+2009 
+2008 
+2007 
+Cash flows from operating activities 
+Net
+income 
+$ 
+10,474 
+$ 
+12,163 
+$ 
+2,918 
+Adjustments
+to reconcile net income to net cash provided by (used in) operating
+activities: 
+Change
+in deferred tax assets 
+(5,398 
+) 
+(7,321 
+) 
+(1,419 
+) 
+Depreciation
+of property and equipment 
+1,018 
+756 
+559 
+Stock-based
+compensation 
+364 
+290 
+288 
+Gain
+on early extinguishment of debt 
+(50 
+) 
+(224 
+) 
+— 
+Amortization
+of debt discounts 
+109 
+201 
+207 
+Amortization
+of deferred financing costs 
+72 
+135 
+137 
+Amortization
+of deferred gain on sale-leaseback 
+— 
+(165 
+) 
+(284 
+) 
+Amortization
+of intangible assets 
+147 
+147 
+147 
+Issuance
+of common stock in connection with legal settlement 
+— 
+— 
+213 
+Fair
+value of warrants issued for services 
+— 
+— 
+22 
+Changes
+in operating assets and liabilities: 
+Accounts
+receivable 
+660 
+(1,615 
+) 
+(67 
+) 
+Net
+costs and estimated earnings in excess of billings 
+1,542 
+(1,383 
+) 
+(1,042 
+) 
+Inventories 
+(1,455 
+) 
+2,153 
+(3,565 
+) 
+Prepaid
+expenses and other assets 
+97 
+(77 
+) 
+19 
+Accounts
+payable and accrued expenses 
+(1,190 
+) 
+2,519 
+(182 
+) 
+Net
+cash provided by (used in) operating activities 
+6,390 
+7,579 
+(2,049 
+) 
+Cash flows from investing activities 
+Purchases
+of property and equipment 
+(795 
+) 
+(739 
+) 
+(488 
+) 
+Cash flows from financing activities 
+(Payments
+on) proceeds from borrowings on lines of credit, net 
+— 
+(4,015 
+) 
+1,353 
+Borrowings
+on long-term debt 
+6,543 
+— 
+— 
+Payments
+on long-term debt 
+(7,069 
+) 
+(3,838 
+) 
+(1,843 
+) 
+Credit
+facility commitment fees 
+— 
+(50 
+) 
+(40 
+) 
+Checks
+drawn in excess of available bank balances 
+— 
+(47 
+) 
+(628 
+) 
+Proceeds
+from stock option exercises 
+939 
+1,374 
+1,120 
+Proceeds
+from warrant exercises 
+— 
+122 
+2,435 
+Proceeds
+from notes receivable from employees 
+— 
+— 
+44 
+Net
+cash provided by (used in) financing activities 
+413 
+(6,454 
+) 
+2,441 
+Effect
+of exchange rate changes on cash 
+(57 
+) 
+— 
+— 
+Increase
+(decrease) in cash and cash equivalents 
+5,951 
+386 
+(96 
+) 
+Cash
+and cash equivalents at beginning of year 
+421 
+35 
+131 
+Cash
+and cash equivalents at end of year 
+$ 
+6,372 
+$ 
+421 
+$ 
+35 
+Supplemental cash flow information: 
+Cash
+paid during the year for: 
+Interest 
+$ 
+545 
+$ 
+1,008 
+$ 
+1,263 
+Income
+taxes 
+462 
+24 
+39 
+Supplemental schedule of non-cash investing and financing
+activities: 
+Fair
+value of common stock issued in settlement of liabilities 
+$ 
+427 
+$ 
+350 
+$ 
+— 
+Conversion
+of redeemable common stock to common stock 
+— 
+3,414 
+— 
+Lease
+incentives in connection with new headquarters lease 
+— 
+1,772 
+— 
+Write-off
+of notes receivable from employees 
+— 
+(5 
+) 
+— 
+38 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements 
+March 31, 2009 
+1. Description of Business and
+Summary of Significant Accounting Policies 
+Description
+of Business 
+Iteris, Inc.
+(including our subsidiary, referred to collectively in these consolidated
+financial statements as “Iteris,” “the Company,” “we,” “our” and “us”) is a leader in the traffic management market
+focused on the development and application of advanced technologies that reduce
+traffic congestion, minimize the environmental impact of traffic congestion and
+improve the safety of surface transportation systems infrastructure. By combining outdoor image processing,
+traffic engineering and information technology, we offer a broad range of
+Intelligent Transportation Systems (“ITS”) and driver safety solutions to
+customers worldwide. Iteris was
+originally incorporated in Delaware in 1987. 
+Basis
+of Presentation 
+Our consolidated financial statements include the accounts of Iteris
+and our subsidiary, Iteris Europe GmbH. All significant intercompany accounts
+and transactions have been eliminated in consolidation. 
+Use
+of Estimates 
+The preparation of consolidated financial statements in conformity with
+accounting principles generally accepted in the United States (“U.S. GAAP”)
+requires our management to make certain estimates and assumptions that affect
+the reported amounts of assets and liabilities and disclosures of contingent
+assets and liabilities at the date of the financial statements, and reported
+amounts of revenues and expenses during the reporting period. Actual results
+could differ from those estimates. Significant estimates made in the
+preparation of the consolidated financial statements include the allowance for
+doubtful accounts, projections of taxable income used to assess realizability
+of deferred tax assets, inventory and warranty reserves, costs to complete
+long-term contracts, overhead rates used in cost-plus contracts, contract reserves,
+the valuation of equity instruments and estimates of future cash flows used to
+assess the recoverability of long-lived assets and the realization of goodwill. 
+Reclassifications 
+Certain reclassifications
+have been made to the prior year financial statements to conform to the current
+year presentation. 
+Revenue
+Recognition 
+Product revenues and related costs of sales are recognized upon the
+transfer of title, which generally occurs upon shipment or, if required, upon
+acceptance by the customer, provided that we believe collectibility of the net
+sales amount is reasonably assured. Accordingly, at the date revenue is
+recognized, the significant uncertainties concerning the sale have been
+resolved. 
+Contract revenues are derived primarily from long-term contracts with
+governmental agencies. Contract revenues include costs incurred plus a portion
+of estimated fees or profits determined on the percentage of completion method
+of accounting based on the relationship of costs incurred to total estimated
+costs. Any anticipated losses on contracts are charged to earnings when
+identified. Changes in job performance and estimated profitability, including
+those arising from contract penalty provisions and final contract settlements,
+may result in revisions to costs and revenues and are recognized in the period
+in which the revisions are determined. Profit incentives are included in
+revenue when their realization is reasonably assured. Costs and estimated
+earnings in excess of billings at March 31, 2009 and 2008 include $684,000
+and $828,000, respectively, that were not billable as certain milestone
+objectives specified in the contracts had not been attained. Substantially all
+costs and estimated earnings in excess of billings at March 31, 2009 are
+expected to be billed and collected during the fiscal year ending March 31,
+2010. 
+In addition to product and contract revenue, we derive revenue from
+technology access fees, the provision of specific non-recurring contract
+engineering services and royalties. Technology access fee revenues are
+recognized evenly over the period in which they are earned. Non-recurring
+contract engineering revenues are recognized in the period in which the related
+services are performed. Royalty revenues are recorded in the period in which
+the royalty is earned, based on unit sales of our products. Technology access
+fee revenues, contract engineering revenues and royalty revenues are included
+in net sales in the accompanying consolidated statements of operations. 
+Revenues from follow-on service and support, for which we charge
+separately, are recorded in the period in which the services are performed. 
+39 
+Table of Contents 
+Concentration
+of Credit Risk 
+Financial instruments that potentially subject us to a concentration of
+credit risk consist principally of cash and cash equivalents and trade accounts
+receivable. 
+Cash and cash equivalents consist primarily of demand deposits and
+money market funds maintained with several financial institutions. Deposits
+held with banks may exceed the amount of insurance provided on such deposits.
+Generally, these deposits may be redeemed upon demand and are maintained with
+high credit quality financial institutions and therefore have minimal credit
+risk. 
+Accounts receivable are primarily derived from revenues earned from
+customers located throughout North America and Europe. We generally do not
+require collateral or other security from customers. Collectibility of
+receivable balances is estimated through review of invoices outstanding greater
+than a certain period of time and ongoing credit evaluations of our customers’
+financial condition. Reserves are maintained for potential credit losses, and
+such losses have historically been within management’s expectations. 
+Fair
+Values of Financial Instruments 
+The fair value of cash
+and cash equivalents, receivables, inventories, accounts payable and accrued
+expenses approximate carrying value because of the short period of time to
+maturity. The fair value of line of credit agreements, long-term debt and
+convertible debentures approximate carrying value because the related effective
+rates of interest approximate current market rates available to us for debt
+with similar terms and similar remaining maturities. 
+Cash and
+Cash Equivalents 
+Cash and cash equivalents consist of cash and short-term investments
+with initial maturities of ninety days or less. 
+Inventories 
+Inventories are stated at
+the lower of cost or market. Cost is determined using the first-in, first-out
+method. 
+Property
+and Equipment 
+Property and equipment
+are recorded at cost and are depreciated over the estimated useful life ranging
+from three to eight years. Leasehold
+improvements are depreciated over the term of the related lease or the
+estimated useful life of the improvement, whichever is shorter. 
+Goodwill
+and Long-Lived Assets 
+In accordance with
+Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Intangible Assets (“SFAS 142”), goodwill is
+tested for impairment on an annual basis in our fourth fiscal quarter or more
+frequently if indicators of impairment exist. 
+The performance of the test involves a two-step process. The first step of the impairment test involves
+comparing the fair value of our reporting units with each respective reporting
+unit’s carrying amount, including goodwill. 
+We determine the fair value of reporting units using the income
+approach. If the carrying amount of a
+reporting unit exceeds the reporting unit’s fair value, the second step of the
+goodwill impairment test is performed to determine the amount of any impairment
+loss. The second step of the goodwill
+impairment test involves comparing the implied fair value of the reporting unit’s
+goodwill with the carrying amount of that goodwill. We performed annual
+impairment assessments of the carrying value of goodwill for each of the years
+ended March 31, 2009, 2008 and 2007. Based on these assessments, we
+determined that no impairment was indicated as the estimated fair value of each
+of our reporting units exceeded its respective carrying value. 
+We evaluate long-lived
+assets for impairment in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ,
+which requires impairment evaluation on long-lived assets used in operations
+when indicators of impairment are present. 
+Reviews are performed to determine whether the carrying value of assets
+is impaired, based on a comparison to undiscounted expected future cash
+flows. If this comparison indicates that
+there is impairment, the impaired asset is written down to fair value, which is
+typically calculated using discounted expected future cash flows and a discount
+rate based upon our weighted average cost of capital adjusted for risks
+associated with the related operations. 
+Impairment is based on the excess of the carrying amount over the fair
+value of those assets. 
+Income
+Taxes 
+We utilize the liability
+method of accounting for income taxes as set forth in SFAS No. 109, Accounting for Income Taxes (“SFAS 109”). Under the liability method, deferred taxes
+are determined based on the temporary differences between the financial
+statement and tax bases of assets and liabilities using enacted tax rates. A valuation allowance is recorded when it is
+more likely than not that all or a portion of the deferred tax assets will not
+be realized. See Note 4. 
+40 
+Table of Contents 
+On April 1, 2007, we
+adopted the provisions of Financial Accounting Standards Board (“FASB”)
+Interpretation No. 48, Accounting for Uncertainty
+in Income Taxes — an Interpretation of FASB Statement No. 109 (“FIN 48”). 
+FIN 48 clarifies the accounting for uncertainty in income taxes by
+establishing minimum standards for the recognition and measurement of tax
+positions taken or expected to be taken in a tax return. Under the requirements
+of FIN 48, we must review all of our tax positions and make a determination as
+to whether each position is more-likely-than-not to be sustained upon
+examination by regulatory authorities. If a tax position meets the
+more-likely-than-not standard, then the related tax benefit is measured based
+on a cumulative probability analysis of the amount that is more-likely-than-not
+to be realized upon ultimate settlement or disposition of the underlying issue. 
+Stock-Based
+Compensation 
+Effective April 1, 2006, we adopted SFAS No. 123 (revised
+2004), Share-Based Payment (“SFAS 123R”), which
+replaced SFAS No. 123, Accounting for Stock-Based
+Compensation (“SFAS 123”), superseded Accounting Principles Board (“APB”)
+Opinion No. 25, Accounting for Stock
+Issued to Employees (“APB 25”), and amended SFAS No. 95, Statement of Cash Flows . 
+SFAS 123R requires all stock-based payments, including grants of
+employee stock options, to be recognized in the statement of operations as an
+expense, based on their grant date fair values with such fair values amortized
+over the requisite service period. We
+elected to use the modified prospective transition method for transition to
+SFAS 123R. Under the modified
+prospective method, SFAS 123R applies to all awards granted or modified after
+the date of adoption. In addition, under
+the modified prospective method, compensation expense will be recognized for
+all stock-based compensation awards granted prior to but not yet vested as of April 1,
+2006, based on grant-date fair values estimated in accordance with the original
+provisions of SFAS 123. 
+The fair value concepts were not changed significantly as a result of
+implementing SFAS 123R; however, in adopting SFAS 123R, companies must choose
+among alternative valuation models and amortization assumptions. The fair value of each stock-based award is
+estimated on the grant date using the Black-Scholes-Merton (“BSM”)
+option-pricing formula. Expected volatility is based on the historical
+volatility of our stock price. The expected life of options granted subsequent
+to the adoption of SFAS 123R is derived based on the historical life of our
+options. The risk-free interest rate for
+periods within the expected life of the option is based on the U.S. Treasury
+interest rates in effect at the time of grant. 
+Additionally, SFAS 123 did not require the estimation of forfeitures in
+the calculation of stock compensation expense; however, SFAS 123R does require
+such estimation and upon adoption of SFAS 123R, we changed our methodology to
+include an estimate of forfeitures. 
+In addition, in
+accordance with SFAS 123R, SFAS 109 and Emerging Issues Task Force (“EITF”)
+Topic D-32, Intraperiod Tax Allocation of
+the Tax Effect of Pretax Income from Continuing Operations , we have
+elected to recognize excess income tax benefits from stock option exercises in
+additional paid-in capital only if an incremental income tax benefit would be
+realized after considering all other tax attributes presently available to us.
+We measure the tax benefit associated with excess tax deductions related to
+stock-based compensation expense by multiplying the excess tax deductions by
+the statutory tax rates. 
+Research
+and Development Expenditures 
+Research and development expenditures are charged to expense
+in the period incurred. 
+Shipping
+and Handling Costs 
+Shipping and handling costs are included as cost of sales in the period
+during which the products ship. 
+Sales Taxes 
+Sales taxes are presented on a net basis (excluded from net sales and
+contract revenues) in the consolidated statements of operations. 
+Advertising
+Expenses 
+Advertising costs are expensed in the period incurred and totaled
+$202,000, $172,000 and $152,000 in the years ended March 31, 2009, 2008
+and 2007, respectively. 
+Warranty 
+We generally
+provide a one to three year warranty from the original invoice date on all
+products, materials and workmanship. 
+Products sold to certain original equipment manufacturer (“OEM”)
+customers sometimes carry longer warranties. Defective products will be either
+repaired or replaced, generally at our option, upon meeting certain criteria. We
+accrue a provision for the estimated costs that may be incurred for product
+warranties relating to a product as a component of cost of sales at the time
+revenue for that product is recognized. 
+The accrued warranty provision is included within accrued expenses in
+the accompanying consolidated balance sheets. 
+41 
+Table of
+Contents 
+Repair
+and Maintenance Costs 
+We incur repair and maintenance costs in the normal course of business.
+Should the activity result in a permanent improvement to one of our leased
+facilities, the cost is capitalized as a leasehold improvement and amortized
+over its useful life or the remainder of the lease period, whichever is
+shorter. Non-permanent repair and maintenance costs are charged to expense as
+incurred. 
+Comprehensive
+Income 
+The
+only component of accumulated other comprehensive income is foreign currency
+translation adjustments. 
+Recent Accounting Pronouncements 
+In September 2006,
+the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, Fair Value Measurements (“SFAS 157”), which defines fair
+value, establishes a framework for measuring fair value, and expands disclosure
+about fair value measurements. SFAS 157 does not require any new fair value
+measurements; rather it specifies valuation methods to be applied when fair
+value measurements are required under existing or future accounting
+pronouncements. SFAS 157 is effective for fiscal years beginning after November 15,
+2007 and interim periods within those fiscal years. In February 2008, the
+FASB issued FASB Staff Position (“FSP”) 157-2, Effective
+Date of FASB Statement No. 157 (“FSP 157-2”), which delays the
+effective date of SFAS 157 for non-financial assets and liabilities to fiscal
+years beginning after November 15, 2008. Generally, SFAS 157 will be
+applied prospectively. With respect to financial assets and liabilities, we
+adopted SFAS 157 in the first quarter of fiscal 2009, for which there was no
+material impact on the consolidated financial statements. We are currently
+evaluating the impact of SFAS 157 and FSP 157-2 with respect to our
+non-financial assets and liabilities and expect to adopt SFAS 157 and FSP 157-2
+with respect to these assets and liabilities in the first quarter of our fiscal
+year ending March 31, 2010. 
+In December 2007,
+the FASB issued SFAS No. 141R, Business Combinations 
+(“SFAS 141R”). SFAS 141R establishes principles and requirements for
+how the acquirer of a business recognizes and measures in its financial
+statements the identifiable assets acquired, the liabilities assumed, and any
+noncontrolling interest in the acquiree. The statement also provides guidance
+for recognizing and measuring the goodwill acquired in the business combination
+and determines what information to disclose to enable users of financial
+statements to evaluate the nature and financial effects of the business
+combination. Additionally, in April 2009, the FASB issued FSP 141R-1, Accounting for Assets Acquired and Liabilities Assumed in a Business
+Combination that Arise from Contingencies (“FSP 141R-1”), which
+amends SFAS 141R to require that assets acquired and liabilities assumed in a
+business combination that are from contingencies be recognized in accordance
+with SFAS 157 if the fair value can be determined during the measurement
+period. SFAS 141R and FSP 141R-1
+are both effective for financial statements issued for fiscal years beginning
+after December 15, 2008. The nature and magnitude of the specific effects
+of adopting SFAS 141R and FSP 141R-1 will depend upon the nature, terms and
+size of any acquisitions we may consummate after the effective date of our
+adoption of SFAS 141R in the first fiscal quarter of our fiscal year ending March 31,
+2010. 
+In April 2008, the
+FASB issued FSP No. 142-3, Determination of the
+Useful Life of Intangible Assets (“FSP 142-3”), which amends the
+guidance about estimating the useful lives of recognized intangible assets and
+requires additional disclosures related to renewing or extending the terms of
+recognized intangible assets under SFAS 142. FSP 142-3 is effective for
+financial statements issued for fiscal years, and interim periods within those
+fiscal years, beginning after December 15, 2008. We currently do not
+expect the adoption of FSP 142-3 will have a material impact on our
+consolidated financial statements. 
+In May 2008, the
+FASB issued SFAS No. 162, The
+Hierarchy of Generally Accepted Accounting Principles (“SFAS 162”).
+SFAS 162 identifies the sources of accounting principles to be used in the
+preparation of financial statements of nongovernmental entities that are
+presented in conformity with U.S. GAAP. SFAS 162 is effective
+60 days following the SEC approval of the Public Company Accounting
+Oversight Board amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted
+Accounting Principles. We currently adhere to the hierarchy of U.S.
+GAAP as presented in SFAS 162, and adoption is not expected to have a
+material impact on our consolidated financial statements. 
+In May 2008, the
+FASB issued FSP APB 14-1, Accounting for Convertible
+Debt Instruments That May Be Settled in Cash upon Conversion (Including
+Partial Cash Settlement) (“FSP APB 14-1”). FSP APB 14-1 clarifies
+that convertible debt instruments that may be settled in cash upon either
+mandatory or optional conversion (including partial cash settlement) are not
+addressed by paragraph 12 of APB Opinion No. 14, Accounting
+for Convertible Debt and Debt Issued with Stock Purchase Warrants .
+Additionally, FSP APB 14-1 specifies that issuers of such instruments should
+separately account for the liability and equity components in a manner that
+will reflect the entity’s nonconvertible debt borrowing rate when interest cost
+is recognized in subsequent periods. FSP APB 14-1 is effective for financial
+statements issued for fiscal years beginning after December 15, 2008, and
+interim periods within those fiscal years, and must be applied on a
+retrospective basis. We plan to adopt FSP APB 14-1 in the first fiscal quarter
+of our fiscal year ending March 31, 2010 and are currently evaluating the
+impact to our consolidated financial statements. 
+In June 2008, the
+FASB issued EITF Issue No. 07-5, Determining Whether an
+Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock 
+(“EITF 07-5”). EITF 07-5 clarifies how to determine whether certain instruments
+or features were indexed to an entity’s own stock under EITF Issue No. 01-6,
+The Meaning of “Indexed to a Company’s Own Stock” (“EITF
+01-6”), and provides guidance to determine what accounting literature may apply
+to a particular equity linked instrument or feature. EITF 07-5 will become 
+42 
+Table of Contents 
+effective for financial
+statements issued for fiscal years beginning after December 15, 2008, and
+interim periods within those fiscal years, and must be applied to all
+instruments outstanding on the date of adoption. We plan to adopt EITF 07-5 in
+the first quarter of our fiscal year ending March 31, 2010 and are
+currently evaluating the impact to our consolidated financial statements. 
+In May 2009, the
+FASB issued SFAS No. 165, Subsequent Events 
+(“SFAS 165”). SFAS 165 provides authoritative accounting literature related to
+evaluating subsequent events that was previously addressed only in the auditing
+literature, and is largely similar to the current guidance in the auditing
+literature with some exceptions that are not intended to result in significant
+changes in practice. SFAS 165 defines subsequent events and also requires the
+disclosure of the date through which an entity has evaluated subsequent events
+and the basis for that date. SFAS 165 is effective on a prospective basis for
+interim or annual financial periods ending after June 15, 2009. We plan to
+adopt SFAS 165 in the first quarter of our fiscal year ending March 31,
+2010 and do not expect it to have a material impact on our consolidated
+financial statements. 
+2. Supplementary Financial
+Information 
+Inventories 
+The following table presents details regarding our inventories: 
+March 31, 
+2009 
+2008 
+(In thousands) 
+Materials
+and supplies 
+$ 
+4,820 
+$ 
+3,031 
+Work
+in process 
+198 
+345 
+Finished
+goods 
+663 
+850 
+$ 
+5,681 
+$ 
+4,226 
+Intangible
+Assets 
+The
+following table presents details regarding our intangible assets: 
+March 31, 2009 
+March 31, 2008 
+Gross 
+Carrying 
+Amount 
+Accumulated 
+Amortization 
+Gross 
+Carrying 
+Amount 
+Accumulated 
+Amortization 
+(In thousands) 
+Intangible
+assets subject to amortization: 
+Developed
+technology 
+$ 
+495 
+$ 
+(482 
+) 
+$ 
+495 
+$ 
+(381 
+) 
+Patents 
+317 
+(220 
+) 
+317 
+(174 
+) 
+Total 
+$ 
+812 
+$ 
+(702 
+) 
+$ 
+812 
+$ 
+(555 
+) 
+Amortization expense for
+intangible assets subject to amortization was $147,000 for each of the years
+ended March 31, 2009, 2008 and 2007. Future estimated amortization expense
+is as follows: 
+Year Ending March 31: 
+(In thousands) 
+2010 
+$ 
+58 
+2011 
+46 
+2012 
+6 
+$ 
+110 
+43 
+Table of Contents 
+Warranty
+Reserve Activity 
+The following table presents activity with respect to our
+accrued warranty obligations: 
+Year Ended March 31, 
+2009 
+2008 
+2007 
+(In thousands) 
+Balance
+at beginning of year 
+$ 
+494 
+$ 
+520 
+$ 
+519 
+Additions
+charged to cost of sales 
+342 
+347 
+630 
+Warranty
+claims 
+(254 
+) 
+(373 
+) 
+(629 
+) 
+Balance
+at end of year 
+$ 
+582 
+$ 
+494 
+$ 
+520 
+Earnings
+Per Share 
+The following table sets forth the computation of basic and diluted
+income per share: 
+Year Ended March 31, 
+2009 
+2008 
+2007 
+(In
+thousands, except per share amounts) 
+Numerator: 
+Net
+income 
+$ 
+10,474 
+$ 
+12,163 
+$ 
+2,918 
+Denominator: 
+Weighted
+average common shares used in basic computation 
+33,964 
+32,723 
+29,698 
+Dilutive
+stock options 
+671 
+1,973 
+3,346 
+Dilutive
+warrants 
+3 
+17 
+304 
+Weighted
+average common shares used in diluted computation 
+34,638 
+34,713 
+33,348 
+Earnings
+per share: 
+Basic 
+$ 
+0.31 
+$ 
+0.37 
+$ 
+0.10 
+Diluted 
+$ 
+0.30 
+$ 
+0.35 
+$ 
+0.09 
+The following shares were
+excluded from the computation of diluted earnings per share as their effect
+would have been 
+anti-dilutive: 
+Year Ended March 31, 
+2009 
+2008 
+2007 
+(In thousands) 
+Stock
+options 
+1,518 
+520 
+582 
+Warrants 
+1,158 
+1,170 
+1,240 
+Convertible
+debentures 
+1,281 
+2,661 
+2,729 
+3. Revolving Line of Credit
+and Long-Term Debt 
+Revolving Line of Credit 
+Prior to October 16,
+2008, we had a credit facility with a bank that provided for line of credit
+borrowings of up to $10.0 million. Under this credit facility, we could borrow
+against our eligible accounts receivable and eligible inventory, as defined in
+the credit agreement. Interest on borrowed amounts under the line of credit was
+payable monthly at the current stated prime rate plus 1.00%. Additionally, we
+were obligated to pay an unused line fee of 0.25% per annum applied to the
+amount by which the maximum credit amount exceeded the average daily principal
+balance during the preceding month. The credit facility required $2,000 in
+monthly collateral management fees and included an early termination fee equal
+to 2% of the total facility during the first year of the agreement and 1% of
+the total facility in the second year of the agreement. The credit facility was
+secured by substantially all of our assets. 
+This credit facility expired on October 15, 2008. 
+Effective October 16,
+2008, we entered into a new $19.5 million credit facility with a different
+bank, which replaced our existing credit facility. This new credit facility provides for a
+two-year revolving line of credit with borrowings of up to $12.0 million and a
+$7.5 million 48-month term note (discussed below). Interest on borrowed amounts under the
+revolving line of credit will be payable monthly at a rate equal to the current
+stated prime rate up to the current stated prime rate plus 0.50%, depending on
+aggregate deposit balances maintained at the bank in relation to the total loan
+commitment under the credit facility (3.75% at March 31, 2009). We are obligated to pay an unused line fee of
+0.25% per annum applied to the average unused portion of the revolving line of
+credit during the preceding month. The
+revolving line of credit does not contain any early termination fees and is
+secured by substantially 
+44 
+Table of Contents 
+all of our assets. As of March 31,
+2009, no amounts were borrowed under the revolving line of credit portion of
+the facility. As part of this credit facility, we may also borrow up to $7.5 million in the form of
+a 48-month term note to retire our convertible debentures as
+discussed below under “Long-Term Debt — Bank Term Notes.” 
+On March 31,
+2009, the available credit under the revolving line of credit was $12.0
+million, all of which was unused. 
+Long-Term Debt 
+Our long-term debt consists of the following: 
+March 31, 
+2009 
+2008 
+(In thousands) 
+Convertible
+debentures, net 
+$ 
+750 
+$ 
+7,566 
+Bank
+term note 
+6,543 
+210 
+Other 
+— 
+34 
+7,293 
+7,810 
+Less
+current portion 
+(2,019 
+) 
+(244 
+) 
+$ 
+5,274 
+$ 
+7,566 
+Convertible
+Debentures, Net. In
+May 2004, we sold and issued subordinated convertible debentures in the
+aggregate original principal amount of $10.1 million. In connection with the
+issuance of the debentures, we issued warrants to purchase an aggregate of
+639,847 shares of our common stock, the value of which was recorded as a debt
+discount against the face amount of the debentures on the date of issuance and
+is being amortized to interest expense over the term of the convertible
+debentures. 
+The debentures
+were due in full on May 19, 2009, provided for 6.0% annual interest,
+payable quarterly, and were convertible into our common stock at an initial
+conversion price of $3.61 per share, subject to certain adjustments, including
+adjustments for dilutive issuances. From May 19, 2008 until the maturity
+date, we were permitted to redeem the debentures at 110% of the principal
+amount. Through March 31, 2009, $250,000 of debentures had been converted
+into 69,252 shares of our common stock. 
+During the year
+ended March 31, 2008, at the holders’ request, we paid $1.8 million in
+cash to retire $2.1 million of convertible debentures early, for which we
+recorded a net gain of $224,000. During
+the year ended March 31, 2009, we early-retired an additional $7.0 million
+of outstanding convertible debentures, also at the holders’ request, for a net
+gain of approximately $50,000. For this retirement we used $300,000 of our cash
+and financed $6.5 million under our new bank term note, which is described
+below under the caption “Bank Term Notes.” The net gains above were recorded
+within other income for their respective fiscal years within the accompanying
+consolidated statements of operations. 
+As of March 31,
+2009, $750,000 of convertible debentures remained outstanding. Subsequently, on
+May 18, 2009, we retired this outstanding balance, which was also financed
+under our bank term note. In accordance with SFAS No. 6, Classifications of Short-Term Obligations Expected to Be Refinanced ,
+we have classified the portion of the remaining outstanding convertible
+debentures financed under our term note subsequent to March 31, 2009 as
+long-term debt in the accompanying condensed consolidated balance sheet as of March 31,
+2009. 
+Bank Term
+Notes. In October 2004,
+we entered into a $5.0 million term note payable with a bank. The note was due
+on May 27, 2008, and provided for monthly principal payments of
+approximately $104,000. The final
+payment against this term note was made in June 2008. 
+Effective October 16,
+2008, we entered into a new $19.5 million credit facility with a different
+bank, as described above. Under this new
+credit facility, we may borrow up to $7.5 million in the form of a 48-month
+term note to retire all outstanding convertible debentures. Principal payments under this term note are
+required to be repaid in 48 monthly installments commencing on June 1,
+2009. Interest on the term note is
+payable monthly at a rate equal to the current stated prime rate plus 0.50% up
+to the current stated prime rate plus 1.00%, depending on aggregate deposit
+balances maintained at the bank in relation to the total loan commitment under
+the credit facility (4.25% at March 31, 2009). We paid an upfront loan commitment fee of
+$28,000 for the term note. The term note contains no early termination fees and,
+along with the new revolving line of credit under the same credit agreement
+(above), is secured by substantially all of our assets. As of March 31,
+2009, $6.5 million had been borrowed against this term note to repay
+convertible debentures. 
+On February 4,
+2009 we entered into an Amended and Restated Loan and Security Agreement with
+our bank which supersedes the agreements entered into on October 16, 2008
+in their entirety. The October 16, 2008 documents were amended and
+restated to clarify certain ambiguities and remove non-applicable
+language. No modifications were made to
+any significant provisions related to the overall amount of the credit
+facility, interest rate calculations, or any financial or non-financial covenant. 
+45 
+Table of Contents 
+Scheduled aggregate maturities of long-term debt principal as of March 31,
+2009 were as follows: 
+Year Ending March 31: 
+(In thousands) 
+2010 
+$ 
+2,019 
+2011 
+2,323 
+2012 
+2,323 
+2013 
+628 
+$ 
+7,293 
+4. Income Taxes 
+For financial reporting purposes, income before income taxes includes
+the following components: 
+Year
+Ended March 31, 
+2009 
+2008 
+2007 
+(In
+thousands) 
+United
+States 
+$ 
+4,927 
+$ 
+6,119 
+$ 
+1,517 
+Foreign 
+250 
+144 
+58 
+$ 
+5,177 
+$ 
+6,263 
+$ 
+1,575 
+The reconciliation of our income tax benefit to taxes computed at U.S.
+federal statutory rates is as follows: 
+Year Ended March 31, 
+2009 
+2008 
+2007 
+(In thousands) 
+Income
+tax provision at statutory rates 
+$ 
+1,761 
+$ 
+2,131 
+$ 
+536 
+State
+income taxes net of federal benefit 
+57 
+(675 
+) 
+(147 
+) 
+Change
+in valuation allowance associated with federal deferred tax assets 
+(6,915 
+) 
+(7,558 
+) 
+(1,895 
+) 
+Compensation
+charges 
+(4 
+) 
+194 
+— 
+Unrecognized
+tax benefits 
+(290 
+) 
+(133 
+) 
+— 
+AMT
+and foreign taxes 
+(8 
+) 
+40 
+24 
+Other
+permanent differences 
+102 
+101 
+139 
+Income
+tax benefit 
+$ 
+(5,297 
+) 
+$ 
+(5,900 
+) 
+$ 
+(1,343 
+) 
+The components of deferred tax assets and liabilities are as follows: 
+46 
+Table of Contents 
+March 31, 
+2009 
+2008 
+(In thousands) 
+Deferred
+tax assets: 
+Net
+operating losses 
+$ 
+13,942 
+$ 
+16,777 
+Credit
+carry forwards 
+247 
+164 
+Deferred
+compensation and payroll 
+1,035 
+1,359 
+Bad
+debt allowance and other reserves 
+672 
+601 
+Other,
+net 
+264 
+167 
+Total
+deferred tax assets 
+16,160 
+19,068 
+Valuation
+allowance 
+— 
+(7,887 
+) 
+Net
+deferred tax assets 
+16,160 
+11,181 
+Deferred
+tax liabilities: 
+Property
+and equipment 
+(104 
+) 
+(160 
+) 
+Acquired
+intangibles 
+(341 
+) 
+(183 
+) 
+Other,
+net 
+31 
+(490 
+) 
+Total
+deferred tax liabilities 
+(414 
+) 
+(833 
+) 
+Net
+deferred tax assets 
+$ 
+15,746 
+$ 
+10,348 
+The
+components of current and deferred federal and state income tax benefits and
+provisions are as follows: 
+Year Ended March 31, 
+2009 
+2008 
+2007 
+(In thousands) 
+Current
+income tax provision: 
+Federal 
+$ 
+(200 
+) 
+$ 
+94 
+$ 
+25 
+State 
+223 
+40 
+32 
+Foreign 
+78 
+40 
+24 
+Deferred
+income tax benefit: 
+Federal 
+(5,261 
+) 
+(5,011 
+) 
+(1,170 
+) 
+State 
+(137 
+) 
+(1,063 
+) 
+(254 
+) 
+Net
+income tax benefit 
+$ 
+(5,297 
+) 
+$ 
+(5,900 
+) 
+$ 
+(1,343 
+) 
+At March 31, 2009, we had approximately $184,000 in federal
+alternative minimum tax credit carryforwards and $30,000 in state alternative
+minimum tax credit carryforwards that can be carried forward indefinitely. We
+had $40.8 million of federal net operating loss carryforwards at March 31,
+2009 that begin to expire in 2019 and $18.4 million of state net operating loss
+carryforwards that begin to expire in 2013. 
+In May 2004, we acquired a greater than 80% ownership interest in
+a former subsidiary and from that date forward, our income taxes are provided
+on a consolidated basis for federal income tax purposes. Due to changes in
+stock ownership, the prior year $44.4 million of federal net operating loss
+carryforwards and other federal tax attributes of Iteris are subject to a Section 382
+limitation estimated at approximately $7.8 million annually which can be utilized
+to offset federal consolidated taxable income. To the extent such limitation is
+not exceeded in a particular year, the excess limitation accumulates and adds
+to subsequent years’ limitations. 
+Pursuant to SFAS 123R, our deferred tax assets at March 31, 2009
+do not include $2.4 million of excess tax benefits from employee stock option
+exercises that are a component of our net operating loss carryforwards. If and
+when such excess tax benefits are realized, stockholders’ equity will be
+adjusted. 
+At March 31, 2009, we determined that it is more likely than not
+that our deferred tax assets will be realized. In making such determination, we
+reviewed all available positive and negative evidence, including reversal of
+deferred tax liabilities, potential carrybacks, projected future taxable
+income, tax planning strategies and recent financial performance. As a result,
+at March 31, 2009, we recorded a reduction to income tax expense of $7.4
+million. 
+Unremitted earnings of our foreign subsidiary have been included in the
+consolidated financial statements without giving effect to the United States
+taxes that may be payable on distribution to the United States because it is
+not anticipated that such earnings will be remitted to the United States. If remitted, the additional United States
+taxes would not be material. 
+47 
+Table of Contents 
+FIN 48 
+As of April 1, 2007,
+we recognized the cumulative impact of the adoption of FIN 48 as a $224,000
+increase to our liability for unrecognized tax benefits with a corresponding
+increase to our accumulated deficit balance. As of March 31, 2009 and
+2008, our gross unrecognized tax benefits were $2.5 million and $2.8 million,
+respectively, of which $1.1 million and $88,000 respectively, if recognized,
+would affect our effective tax rate. The gross unrecognized tax benefits differ
+from the amount that would affect our effective tax rate due primarily to the impact
+of the valuation allowance on such differences. 
+Our continuing practice
+is to recognize interest and/or penalties related to income tax matters in
+income tax expense. As of March 31,
+2009 and 2008, we had accrued cumulatively $39,000 and $28,000, respectively,
+for the payment of interest and penalties. 
+A reconciliation of the
+beginning and ending balances of the total amounts of gross unrecognized tax
+benefits is as follows (in thousands): 
+Gross
+unrecognized tax benefits at April 1, 2007 
+$ 
+1,584 
+Increases
+in tax positions for prior year 
+1,160 
+Decreases
+in tax positions for prior year 
+(147 
+) 
+Increases
+in tax positions for current year 
+327 
+Lapse
+in statute of limitations 
+(136 
+) 
+Gross
+unrecognized tax benefits at March 31, 2008 
+2,788 
+Increases
+in tax positions for prior year 
+155 
+Decreases
+in tax positions for prior year 
+(36 
+) 
+Increases
+in tax positions for current year 
+22 
+Lapse
+in statute of limitations 
+(404 
+) 
+Gross
+unrecognized tax benefits at March 31, 2009 
+$ 
+2,525 
+We anticipate a decrease
+in gross unrecognized tax benefits of approximately $300,000 within the next
+twelve months based on federal and state statute expirations in various
+jurisdictions. 
+We are subject to
+taxation in the United States and various states. We are subject to U.S. federal tax
+examination for fiscal tax years ended March 31, 2006 and state as well as
+local income tax examination for fiscal tax years ended March 31, 2005. 
+5. Commitments and Contingencies 
+Litigation 
+On June 29,
+2004, a supplier to Mariner Networks, Inc., a former subsidiary of Iteris
+that was discontinued in the fiscal year ended March 31, 2002, filed a
+complaint in Orange County Superior Court against us alleging various breaches
+of written contract claims arising out of alleged purchase orders. On July 20, 2006, we entered into a
+settlement agreement in connection with this matter. The dispute was settled in full for $688,000
+payable as follows: (i) we issued
+88,912 shares of our common stock on August 18, 2006 valued at $213,000
+based on the closing sales price of our common stock on the date of issuance; (ii) we
+made a cash payment of $125,000 on October 20, 2006; and (iii) we are
+obligated to pay $350,000 in cash in equal monthly installments of $9,700 over
+three years beginning in November 2006 through October 2009. In connection with this settlement, we
+recorded a charge of $635,000, representing the fair value of the settlement,
+within other expense in the accompanying consolidated statement of operations
+for the year ended March 31, 2007. 
+From
+time to time, we have been involved in litigation relating to claims arising
+out of our operations in the normal course of business. We currently are not a
+party to any legal proceedings, the adverse outcome of which, in management’s
+opinion, individually or in the aggregate, would have a material adverse effect
+on our consolidated results of operations, financial position or cash flows. 
+Furthermore,
+from time to time, we have experienced unforeseen developments in contingencies
+related to our former subsidiaries. For
+example, we have been the subject of a number of routine tax audits for time
+periods and jurisdictions related to the businesses of our former subsidiaries,
+some of which are still in process. 
+Although the development and ultimate outcome of these and other
+unforeseen matters cannot be predicted with any certainty, our management does
+not believe that we are presently involved in any matters related to our former
+subsidiaries that would have a material adverse effect on our consolidated
+results of operations, financial position or cash flows. 
+48 
+Table of Contents 
+Operating
+Leases 
+In May 2007, we entered into an agreement to lease 52,000 square
+feet of space in Santa Ana, California for a term of 88 months. In September 2007,
+we relocated our headquarters and principal operations into this space. The
+monthly lease rate is $102,000 during the first year of the lease and increases
+each year thereafter, up to a maximum of $120,000 during the last year of the
+lease. The lease may be extended for a period of five years, at our option, at
+a lease rate to be based on the market lease rate for comparable property
+determined as of the commencement date of the extension period. Additionally,
+the lease agreement provides for $1.8 million in incentives in the form of
+tenant improvement allowances, which we recorded as deferred rent and
+capitalized leasehold improvements in our consolidated balance sheet. The deferred rent amount will reduce future
+rent expense over the term of the lease, and the capitalized leasehold
+improvements amount will be depreciated over the initial term of the lease (the
+estimated useful life of the related leasehold improvements). 
+We have lease commitments for facilities in various locations
+throughout the United States as well as certain other equipment. Future minimum rental payments under these
+noncancelable operating leases at March 31, 2009 were as follows: 
+Year Ending March 31: 
+(In thousands) 
+2010 
+$ 
+2,010 
+2011 
+1,741 
+2012 
+1,468 
+2013 
+1,371 
+2014 
+1,393 
+Thereafter 
+1,064 
+$ 
+9,047 
+Rent expense totaled $1.8 million, $2.1 million and $2.2 million for
+the years ended March 31, 2009, 2008 and 2007, respectively. 
+We previously had recorded on our consolidated balance sheet a deferred
+gain related to the May 2002 sale and leaseback of our prior headquarters
+in Anaheim, California. The deferred
+gain was amortized over the term of the underlying lease, which terminated in September 2007,
+and resulted in a realized gain of $165,000 in the fiscal year ended March 31,
+2008 and $284,000 in the fiscal year ended March 31, 2007. 
+We previously subleased office space to MAXxess Systems, Inc. (“MAXxess”),
+one of our former subsidiaries that we sold in September 2003 and is
+currently owned by an investor group that includes two of our directors, one of
+which is the Chief Executive Officer of MAXxess. At March 31, 2009, MAXxess
+owed us an aggregate of $274,000 related to this sublease, which terminated in September 2007,
+and certain related ancillary services that we provided to MAXxess. Although we have fully reserved for amounts
+owed to us by MAXxess under the terms of this sublease, we intend to continue
+to pursue full payment of any and all amounts due from MAXxess. 
+Inventory
+Purchase Commitments 
+At March 31, 2009, we had firm commitments to purchase
+approximately $3.8 million of inventory during the first and second quarters of
+our fiscal year ending March 31, 2010. 
+Deferred
+Compensation Plan 
+In 1986, we
+adopted the Executive Deferral Plan (the “1986 Plan”) under which certain
+executives were able to defer a portion of their annual compensation into the
+1986 Plan. All deferred amounts earned interest, generally with no guaranteed
+rate of return. During the year ended March 31,
+2003, we adopted the Deferred Compensation Plan, and all assets of the 1986
+Plan were transferred into the Deferred Compensation Plan. No compensation withholdings were deferred
+under the 1986 Plan or the Deferred Compensation Plan in the years ended March 31,
+2009, 2008 and 2007. 
+At March 31, 2009, the Deferred Compensation Plan held 23,844
+shares of our common stock, which we have presented as an aggregated $31,000
+deferred compensation plan liability in the accompanying consolidated balance
+sheet. At March 31, 2008, the Deferred Compensation Plan held 167,177
+shares of our common stock and $5,000 in cash. 
+Changes in the value of Iteris common stock held by the Deferred
+Compensation Plan are determined based on changes in the quoted market price of
+our common stock at the close of each reporting period and presented within
+operating expenses in the accompanying consolidated statements of operations.
+As a result of such changes in the value of Iteris common stock, we recorded
+expense of $72,000, expense of $21,000 and a benefit of $91,000 in the years
+ended March 31, 2009, 2008 and 2007, respectively. The original $31,000 cost basis of shares of
+Iteris common stock held in the Deferred Compensation Plan at March 31,
+2009 has been recorded as a contra-equity account in the accompanying
+consolidated financial statements. 
+49 
+Table of Contents 
+6. Stockholders’ Equity 
+Preferred
+Stock 
+Our certificate of incorporation provides for the issuance of up to
+2,000,000 shares of preferred stock. As of March 31, 2009 and 2008, there
+were no outstanding shares of preferred stock, and we do not currently have any
+plans to issue any shares of preferred stock. Our Board of Directors is
+authorized to issue from time to time such authorized but unissued shares of
+preferred stock in one or more series and to fix or alter the designations,
+preferences, rights and any qualifications, limitations or restrictions of the
+shares of each such series, including the dividend, conversion, voting,
+redemption and liquidation rights. 
+Common
+Stock and Common Stock Warrants 
+On September 28,
+2006, we issued warrants to purchase an aggregate 246,250 shares of common
+stock at an exercise price of $3.25 with a five-year life to an existing
+shareholder in exchange for the early exercise of 1,250,000 outstanding warrants
+with an exercise price of $1.61. These
+new warrants were immediately exercisable and are callable by us if the market
+price of our common stock trades for 20 consecutive days at a price greater
+than or equal to two times the exercise price of the warrants. The fair value of these new warrants was
+$320,000 calculated using the BSM option-pricing formula. The warrants were considered a cost of
+raising capital and were recorded in equity. 
+In
+connection with the issuance of the above-described warrants, we are party to a
+registration rights agreement that contains provisions under which we could be
+subjected to liquidated damages should it fail to maintain effective
+registration statements for the shares of common stock issuable upon exercise
+of the warrants. These warrants have
+been accounted for within equity in the consolidated balance sheets as of March 31,
+2009 and 2008 in accordance with EITF Issue No. 00-19 Accounting
+for Derivative Financial Instruments Indexed to, and Potentially Settled in, a
+Company’s Own Stock , and, accordingly, no liabilities have been
+recorded in connection therewith. As of March 31,
+2009, no liquidated damages were payable under the provisions of the
+registration rights agreement associated with these warrants. 
+The following table summarizes information regarding outstanding
+warrants to purchase our common stock as of March 31, 2009: 
+Range of Exercise Prices 
+Warrants 
+Outstanding 
+Weighted Average 
+Remaining 
+Contractual Life 
+Weighted 
+Average Exercise 
+Price 
+(In thousands) 
+(Years) 
+$1.42 
+15 
+4.4 
+$ 
+1.42 
+$3.25 
+246 
+1.9 
+3.25 
+$3.61
+to $4.03 
+674 
+0.1 
+3.93 
+$5.00
+to $5.26 
+230 
+0.7 
+5.18 
+1,165 
+0.7 
+$ 
+4.00 
+All of the outstanding warrants were exercisable at March 31,
+2009. Warrants to purchase an aggregate
+of 246,260 shares of common stock at an exercise price of $3.25 per share
+are callable by us if the market price of our common stock trades for 20
+consecutive days at a price equal to or greater than two times the exercise
+price of the warrants. Warrants to purchase an aggregate of 75,000 shares
+of common stock at an exercise price of $5.00 per share are callable by us if
+the market price of our common stock trades for 20 consecutive days at a
+price equal to or greater than one and a half times the exercise price of the
+warrants. 
+In May 2009, 673,883 warrants associated with our convertible
+debentures (see Note 3) with a weighted average exercise price of $3.93 expired
+unexercised. 
+The
+following summarizes common stock reserved for future issuance at March 31,
+2009: 
+(In thousands) 
+Shares
+issuable under stock options plans 
+3,760 
+Shares
+issuable under the exercise of warrants 
+1,165 
+4,925 
+Upon the exercise of warrants or stock options, we
+issue new shares of common stock from our authorized shares. 
+50 
+Table of Contents 
+7. Associate Benefit Plans 
+Stock
+Option Plans 
+On September 21,
+2007, our stockholders approved the 2007 Omnibus Incentive Plan (the “2007 Plan”),
+which provides that options to purchase shares of our unissued common stock may
+be granted to our employees, officers, consultants and directors at exercise
+prices which are equal to or greater than the fair market value of our common
+stock on the date of grant. Options expire no more than ten years after the
+date of grant and generally vest at the rate of 25% on each of the first four
+anniversaries of the grant date. The 2007 Plan also allows for the issuance of
+stock appreciation rights, restricted stock, restricted stock units and other
+stock-based awards based on the value of our common stock. New shares are
+issued to satisfy stock option exercises and share issuances under the 2007
+Plan. As of March 31, 2009, options to purchase approximately 404,000
+shares of common stock were outstanding under the 2007 Plan. 
+Our 1997 Stock
+Incentive Plan (the “1997 Plan”) terminated in September 2007; however,
+all stock options outstanding under the 1997 Plan will remain outstanding
+pursuant to the terms of such stock options. As of March 31, 2009, options
+to purchase approximately 1.3 million shares of our common stock were
+outstanding under the 1997 Plan. 
+In connection with
+our merger with the Iteris Subsidiary in 2004, we assumed the 1998 Stock
+Incentive Plan (the “1998 Plan”) of the Iteris Subsidiary and all outstanding
+options granted thereunder. As of March 31, 2009, options to purchase
+approximately 1.6 million shares of our common stock were outstanding under the
+1998 Plan. No further options may be granted under the 1998 Plan. 
+Certain options
+granted under the 2007 Plan, the 1997 Plan and the 1998 Plan (collectively, the
+“Plans”) provide for accelerated vesting of unvested options in the event of a
+change in control under certain circumstances. These change-in-control
+provisions meet the criteria of a performance condition under SFAS 123R. 
+A summary of
+activity in the Plans for the year ended March 31, 2009 is as follows: 
+Options 
+Weighted 
+Average 
+Exercise 
+Price Per 
+Share 
+Weigthed 
+Average 
+Remaining 
+Contractual 
+Life 
+Aggregate 
+Intrinsic 
+Value 
+(In thousands) 
+(Years) 
+(In thousands) 
+Options
+outstanding at March 31, 2008 
+4,524 
+$ 
+1.83 
+Granted 
+30 
+2.10 
+Exercised 
+(785 
+) 
+1.20 
+Forfeited 
+(20 
+) 
+2.58 
+Expired 
+(435 
+) 
+2.28 
+Options
+outstanding at March 31, 2009 
+3,314 
+$ 
+1.92 
+4.0 
+$ 
+346 
+Vested
+and expected to vest at March 31, 2009 
+3,245 
+$ 
+1.91 
+3.9 
+$ 
+346 
+Options
+exercisable at March 31, 2009 
+2,857 
+$ 
+1.85 
+3.4 
+$ 
+346 
+Options
+exercisable at March 31, 2009 pursuant to a change-in-control 
+3,314 
+$ 
+1.92 
+4.0 
+$ 
+346 
+At March 31,
+2009, there were approximately 446,000 shares of common stock available for
+grant under the 2007 Plan. 
+Stock-Based Compensation 
+The grant date fair value of options granted was estimated using the
+following weighted-average assumptions: 
+Year Ended March 31, 
+2009 
+2008 
+2007 
+Dividend
+yield 
+— 
+% 
+— 
+% 
+— 
+% 
+Expected
+life - years 
+7.0 
+7.0 
+7.0 
+Risk-free
+interest rate 
+3.3 
+% 
+3.8 
+% 
+4.7 
+% 
+Expected
+volatility of common stock 
+0.75 
+0.80 
+0.90 
+51 
+Table of Contents 
+A summary of
+certain fair value and intrinsic value information is as follows: 
+Year Ended March 31, 
+2009 
+2008 
+2007 
+(In thousands , except per share
+amounts) 
+Weighted
+average grant date fair value per share of options
+granted 
+$ 
+1.50 
+$ 
+1.83 
+$ 
+1.92 
+Intrinsic
+value of options exercised 
+771 
+2,555 
+2,288 
+At March 31,
+2009, there was approximately $836,000 of total unrecognized compensation
+expense related to unvested stock options. 
+This expense is expected to be recognized over a weighted-average period
+of approximately 2.7 years. If there are any modifications or cancellations of
+the underlying unvested stock options, we may be required to accelerate,
+increase or cancel any remaining unearned stock-based compensation expense.
+Future stock-based compensation expense and unearned stock-based compensation
+will increase to the extent that we issue additional stock options or other
+stock-based awards. 
+Associate Incentive Programs 
+Under the terms of a Profit Sharing Plan, we may contribute to a trust
+fund such amounts as are determined annually by the Board of Directors. No
+contributions were made during the years ended March 31, 2009, 2008 and
+2007. 
+In May 1990, we adopted a 401(k) Plan as an amendment and
+replacement of the former Associate Stock Purchase Plan that was an additional
+feature of the Profit Sharing Plan. Under the 401(k) Plan, eligible
+associates voluntarily contribute to the plan, up to IRS maximums, through
+payroll deductions. We match up to 90% of contributions, based on years of
+service, up to a stated limit. Under the provisions of the 401(k) Plan,
+associates have various investment choices, one of which is the purchase of
+Iteris common stock at market price. Our matching contributions were
+approximately $753,000, $401,000 and $480,000 for the years ended March 31,
+2009, 2008 and 2007, respectively. 
+8. Business Segment and
+Geographic Information 
+We currently operate in three reportable segments: Roadway Sensors,
+Vehicle Sensors and Transportation Systems. The Roadway Sensors segment
+includes our Vantage and VersiCam vehicle detection products and systems for
+traffic intersection control, incident detection and certain highway
+traffic data collection applications. The Vehicle Sensors segment includes our
+lane departure warning products and is comprised of all activities related to
+vehicle safety. The Transportation Systems segment includes transportation
+engineering and consulting services, and the development of transportation
+management and traveler information systems for the ITS industry. The accounting
+policies of our reportable segments are the same as those described in the
+summary of significant accounting policies in Note 1. Beginning April 1, 2007, we increased
+the portion of our corporate expenses that we allocate to our segments such
+that substantially all corporate expenses are allocated. Interest, amortization of certain intangibles
+and certain corporate expenses are still not allocated to the segments. The
+reportable segments are each managed separately because they manufacture and
+distribute distinct products or provide services with different processes. All
+segment revenues are derived from external customers. Segment assets are not
+disclosed because the discrete financial information provided to and reviewed
+by our chief operating decision maker does not separately identify segment
+assets. 
+52 
+Table of Contents 
+Selected financial information for our reportable segments as of and
+for the years ended March 31, 2009, 2008 and 2007 is as follows: 
+Roadway 
+Sensors 
+Vehicle 
+Sensors 
+Transportation 
+Systems 
+Total 
+(In thousands) 
+Year Ended March 31, 2009 
+Product
+revenue 
+$ 
+27,197 
+$ 
+9,913 
+$ 
+— 
+$ 
+37,110 
+Service
+and other revenue 
+— 
+1,317 
+30,932 
+32,249 
+Stock-based
+compensation 
+30 
+48 
+50 
+128 
+Depreciation
+and amortization 
+198 
+137 
+249 
+584 
+Allocated
+goodwill 
+8,197 
+4,671 
+14,906 
+27,774 
+Segment
+income 
+3,415 
+569 
+2,216 
+6,200 
+Year Ended March 31, 2008 
+Product
+revenue 
+$ 
+28,452 
+$ 
+10,016 
+$ 
+— 
+$ 
+38,468 
+Service
+and other revenue 
+— 
+1,858 
+24,837 
+26,695 
+Stock-based
+compensation 
+18 
+45 
+27 
+90 
+Depreciation
+and amortization 
+107 
+130 
+147 
+384 
+Allocated
+goodwill 
+8,197 
+4,671 
+14,906 
+27,774 
+Segment
+income 
+5,062 
+552 
+2,094 
+7,708 
+Year Ended March 31, 2007 
+Product
+revenue 
+$ 
+27,261 
+$ 
+6,408 
+$ 
+— 
+$ 
+33,669 
+Service
+and other revenue 
+— 
+2,579 
+22,049 
+24,628 
+Stock-based
+compensation 
+37 
+54 
+78 
+169 
+Depreciation
+and amortization 
+82 
+138 
+126 
+346 
+Allocated
+goodwill 
+8,197 
+4,671 
+14,906 
+27,774 
+Segment
+income (loss) 
+6,035 
+(2,625 
+) 
+2,551 
+5,961 
+The following reconciles segment income to consolidated income before
+income taxes: 
+Year Ended March 31, 
+2009 
+2008 
+2007 
+(In thousands) 
+Segment income: 
+Total
+income from reportable segments 
+$ 
+6,200 
+$ 
+7,708 
+$ 
+5,961 
+Unallocated amounts: 
+Corporate
+and other expenses 
+(346 
+) 
+(266 
+) 
+(1,986 
+) 
+Amortization
+of intangible assets 
+(147 
+) 
+(147 
+) 
+(147 
+) 
+Other
+income, net 
+116 
+252 
+(653 
+) 
+Interest
+expense, net 
+(646 
+) 
+(1,284 
+) 
+(1,600 
+) 
+Income
+before income taxes 
+$ 
+5,177 
+$ 
+6,263 
+$ 
+1,575 
+Significant Customer and Geographic Information 
+No single customer accounted for more than 10% of our total net sales
+and contract revenues for the years ended March 31, 2009 and 2008. One
+customer within our Roadway Sensors segment accounted for approximately 12.4%
+of our total net sales and contract revenues for the year ended March 31,
+2007. 
+The Roadway Sensors segment had one customer who accounted for 19.3%,
+16.9% and 26.5% of total segment revenue for the years ended March 31,
+2009, 2008 and 2007, respectively. 
+The Vehicle Sensors segment had three customers who accounted for an
+aggregate of 63.3% of total segment revenue for the year ended March 31,
+2009; three customers who accounted for an aggregate of 60.9% of total segment
+revenue for the year ended March 31, 2008; and three customers who
+accounted for an aggregate of 64.2% of total segment revenue for the year ended
+March 31, 2007. 
+53 
+Table of Contents 
+The Transportation Systems segment had one customer who accounted for
+11.5% of segment revenue for the year ended March 31, 2009 and one
+customer who accounted for 13.3% of total segment revenue for the year ended March 31,
+2007. 
+At March 31, 2009 and 2008, our gross accounts receivable from
+governmental agencies and prime government contractors were approximately $6.5
+million and $6.4 million, respectively. No individual customer or government
+agency had a receivable balance at March 31, 2009 or 2008 greater than 10%
+of our total trade accounts receivable balances as of March 31, 2009 and
+2008, respectively. 
+Our total net sales and contract revenues derived from all independent
+customers located outside the United States approximated 15%, 12% and 6% for
+the years ended March 31, 2009, 2008 and 2007, respectively. 
+Our assets are held substantially in the United States. 
+9. Quarterly Financial Data (Unaudited) 
+Quarter Ended: 
+Total Net 
+Sales and 
+Contract 
+Revenues 
+Gross Profit 
+Net 
+Income 
+Basic 
+Earnings 
+per Share 
+Diluted 
+Earnings 
+per Share 
+(In thousands, except per share amounts) 
+June 30,
+2008 
+$ 
+17,442 
+$ 
+7,752 
+$ 
+666 
+$ 
+0.02 
+$ 
+0.02 
+September 30,
+2008 
+19,066 
+7,875 
+1,067 
+0.03 
+0.03 
+December 31,
+2008 
+16,462 
+6,504 
+741 
+0.02 
+0.02 
+March 31,
+2009 
+16,389 
+5,788 
+8,000 
+0.23 
+0.23 
+$ 
+69,359 
+$ 
+27,919 
+$ 
+10,474 
+$ 
+0.31 
+* 
+$ 
+0.30 
+* 
+June 30,
+2007 
+$ 
+15,757 
+$ 
+7,094 
+$ 
+1,096 
+$ 
+0.03 
+$ 
+0.03 
+September 30,
+2007 
+16,976 
+7,262 
+2,170 
+0.07 
+0.06 
+December 31,
+2007 
+15,363 
+6,500 
+954 
+0.03 
+0.03 
+March 31,
+2008 
+17,067 
+7,441 
+7,943 
+0.24 
+0.23 
+$ 
+65,163 
+$ 
+28,297 
+$ 
+12,163 
+$ 
+0.37 
+* 
+$ 
+0.35 
+* 
+* Annual per share amounts may not agree to
+the sum of the quarterly per share amounts due to differences between average
+shares outstanding during the periods. 
+10. Subsequent Events 
+Purchase Acquisition 
+In April 2009,
+we completed the acquisition of certain assets of Hamilton Signal, Inc., a
+privately-held developer of video processing algorithms enabling state and
+local governments to conduct real-time analysis on fixed and Pan-Tilt-Zoom
+camera feeds. The total purchase consideration was approximately $518,000, for
+which we paid $300,000 in cash upon execution of the purchase agreement (the “Closing”),
+and for which we are scheduled to pay an additional (i) $106,000 on the one-year
+anniversary of the Closing and (ii) approximately $112,000 on the two-year
+anniversary of the Closing, pursuant to the purchase agreement. The seller is
+also eligible to receive additional consideration based on future net sales of
+certain products, subject to certain limitations, as further described in the
+purchase agreement. 
+Employment Termination 
+In May 2009,
+as part of an internal reorganization, we terminated the employment of the
+Senior Vice President and General Manager of our Vehicle Sensors segment. We
+expect to incur a charge of approximately $100,000 in the first quarter of the
+fiscal year ending March 31, 2010 related to certain severance benefits to
+be paid in connection with the termination agreement. 
+54 
+Table of Contents 
+Exhibit Index 
+Exhibit 
+Number 
+Description 
+Where Located 
+3.1 
+Amended and Restated Certificate of Incorporation of
+the registrant 
+Exhibit 3.1 to the registrant’s Current
+Report on Form 8-K as filed with the SEC on October 28, 2004 
+3.2 
+Certificate of Amendment to Amended and Restated
+Certificate of Incorporation effective September 26, 2007 
+Exhibit 3.2 to the registrant’s Quarterly
+Report on Form 10-Q for the quarter ended September 30, 2007 as
+filed with the SEC on November 13, 2007 
+3.3 
+Bylaws of the registrant, as amended 
+Exhibit 4.2 to the registrant’s Registration
+Statement on Form S-1 (Reg. No. 033-67932) as filed with the SEC on
+July 6, 1993 
+3.4 
+Certificates of Amendment to Bylaws of the
+registrant dated April 24, 1998 and August 10, 2001 
+Exhibit 3.4 to the registrant’s Annual
+Report on Form 10-K/A for the year ended March 31, 2003 as filed
+with the SEC on July 29, 2003 
+3.5 
+Certificate of Amendment to Bylaws of registrant
+dated September 9, 2004 
+Exhibit 3.1 to the registrant’s Quarterly
+Report on Form 10-Q for the quarter ended September 30, 2004 as
+filed with the SEC on November 15, 2004 
+3.6 
+Certificate of Amendment to Bylaws of registrant
+effective September 16, 2005 
+Exhibit 3.5 to the registrant’s Annual
+Report on Form 10-K for the year ended March 31, 2007 
+3.7 
+Certificate of Amendment to Bylaws of registrant
+effective December 7, 2007 
+Exhibit 3.1 to the registrant’s Current
+Report on Form 8-K as filed with the SEC on December 13, 2007 
+4.1 
+Specimen of common stock certificate 
+Exhibit 4.1 to registrant’s Registration
+Statement on Form 8-A as filed with the SEC on December 8, 2004 
+4.2 
+Amended and Restated Rights Agreement, dated as of
+May 10, 2004, by and between the registrant and U.S. Stock Transfer
+Corporation, including exhibits thereto 
+Exhibit 99.1 to the registrant’s
+Registration Statement on Form 8-A/A as field with the SEC on June 18,
+2004 
+10.1* 
+Profit Sharing Plan and Trust 
+Exhibit 10.3 to the registrant’s Amendment
+No. 2 to the Registration Statement on Form S-8 (Reg.
+No. 002-98656) as filed with the SEC on May 5, 1988 
+10.2* 
+Amendment Nos. 3 and 4 to the Profit Sharing Plan
+and Trust 
+Exhibits 4.3.1 and 4.3.2, respectively, to
+Amendment No. 3 to the registrant’s Registration Statement on
+Form S-3 (Reg. No. 002-86220) as filed with the SEC on
+June 13, 1990 
+10.3* 
+Form of Executive Deferral Plan between the
+registrant and certain employees of the registrant 
+Exhibit 10.4 to the registrant’s Annual
+Report on Form 10-K for the year ended March 31, 1988 
+10.4 
+Form of Indemnity Agreement entered into by the
+registrant and certain of its officers and directors 
+Exhibit 19.4 to the registrant’s Quarterly
+Report on Form 10-Q for the quarter ended September 30, 1988 
+10.5 
+Form of Indemnification Agreement entered into
+by the registrant and certain of its officers and directors 
+Exhibit 10.5 to the registrant’s Annual
+Report on Form 10-K for the year ended March 31, 2004 as filed with
+the SEC on June 29, 2004 
+10.6* 
+1997 Stock Incentive Plan (the “1997 Plan”) as
+amended on May 3, 2003, as further amended on December 15, 2004 
+Exhibit 10.32 to the registrant’s Annual
+Report on Form 10-K for the year ended March 31, 2005 as filed with
+the SEC on July 14, 2005 
+Table
+of Contents 
+Exhibit Number 
+Description 
+Where Located 
+10.7* 
+Form of Notice of Grant of Stock Option 
+Exhibit 99.2 to the registrant’s
+Registration Statement on Form S-8 (File No. 333-30396) as filed
+with the SEC on February 14, 2000 
+10.8* 
+Form of Stock Option Agreement 
+Exhibit 99.3 to the registrant’s
+Registration Statement on Form S-8 (File No. 333-30396) as filed
+with the SEC on February 14, 2000 
+10.9* 
+Form of Addendum to Stock Option
+Agreement—Involuntary Termination Following Corporate Transaction or Change
+in Control 
+Exhibit 99.4 to the registrant’s
+Registration Statement on Form S-8 (File No. 333-30396) as filed
+with the SEC on February 14, 2000 
+10.10* 
+Form of Addendum to Stock Option
+Agreement—Limited Stock Appreciation Rights 
+Exhibit 99.5 to the registrant’s
+Registration Statement on Form S-8 (File No. 333-30396) as filed
+with the SEC on February 14, 2000 
+10.11* 
+Form of Stock Issuance Agreement 
+Exhibit 99.6 to the registrant’s
+Registration Statement on Form S-8 (File No. 333-30396) as filed
+with the SEC on February 14, 2000 
+10.12* 
+Form of Addendum to Stock Issuance
+Agreement—Involuntary Termination Following Corporate Transaction/Change in
+Control 
+Exhibit 99.7 to the registrant’s
+Registration Statement on Form S-8 (File No. 333-30396) as filed
+with the SEC on February 14, 2000 
+10.13* 
+Form of Notice of Grant of Automatic Stock
+Option—Initial Grant 
+Exhibit 99.8 to Exhibit 99.8 to
+registrant’s Registration Statement on Form S-8 (File
+No. 333-30396) as filed with the SEC on February 14, 2000 
+10.14* 
+Form of Notice of Grant of Automatic Stock
+Option—Annual Grant 
+Exhibit 99.9 to the registrant’s
+Registration Statement on Form S-8 (File No. 333-30396) as filed
+with the SEC on February 14, 2000 
+10.15* 
+Form of Automatic Stock Option Agreement. 
+Exhibit 99.10 to the registrant’s
+Registration Statement on Form S-8 (File No. 333-30396) as filed
+with the SEC on February 19, 2000 
+10.16 
+Amended and Restated Agreement of Purchase and Sale
+and Escrow Instructions, dated February 19, 2002, by and between
+Iteris, Inc. and 1515 South Manchester, LLC 
+Exhibit 2.1 to the registrant’s Current
+Report on Form 8-K as filed with the SEC on June 12, 2002 
+10.17* 
+Iteris Inc. 1998 Stock Incentive Plan (as amended on
+February 7, 2000) 
+Exhibit 10.24 to the registrant’s Annual
+Report on Form 10-K for the year ended March 31, 2005 as filed with
+the SEC on July 14, 2005 
+10.18* 
+Form of Notice of Grant, including forms of
+Option Agreement and Stock Purchase Agreement for the following directors and
+executive officers: Gary Hernandez, Dr. Hartmut Marwitz, Paul E. Wright,
+Jack Johnson, Richard D. Crawshaw, Gregory McKhann, Francis Memole, James S.
+Miele, Abbas Mohaddes and Stephen Edwin Rowe 
+Exhibit 99.2 to the registrant’s
+Registration Statement on Form S-8 (File No. 333-126834) as filed
+with the SEC on July 22, 2005 
+10.19* 
+Form of Addendum to Stock Option Agreement 
+Exhibit 99.3 to the registrant’s
+Registration Statement on Form S-8 (File No. 333-126834) as filed
+with the SEC on July 22, 2005 
+Table
+of Contents 
+Exhibit Number 
+Description 
+Where Located 
+10.20* 
+Form of 1997 Stock Option Agreements 
+Exhibit 99.4 to the registrant’s
+Registration Statement on Form S-8 (File No. 333-126834) as filed
+with the SEC on July 22, 2005 
+10.21* 
+Iteris, Inc. Deferred Compensation Savings Plan
+and Grantor Trust 
+Exhibit 10.31 to the registrant’s Annual
+Report on Form 10-K for the year ended March 31, 2005 as filed with
+the SEC on July 14, 2005 
+10.22+ 
+Cooperative Agreement for Development, Manufacture,
+Marketing and Sale of Products to the Class 1 and Class 2 Vehicle
+Markets Incorporating Iteris’ LDWS Technology (Valeo Schalter and Sensoren
+GmbH) 
+Exhibit 10.1 to the registrant’s Quarterly
+Report on Form 10-Q for the quarter ended June 30, 2004 as filed
+with the SEC on August 16, 2004 
+10.23 
+Warrant Exercise Agreement dated September 27,
+2006 by and among the registrant and Special Situations Fund III QP, L.P.,
+Special Situations Fund III, L.P., Special Situations Cayman Fund, L.P. and
+Special Situations Private Equity Fund, L.P. 
+Exhibit 10.1 to the registrant’s Quarterly
+Report on Form 10-Q for the quarter ended September 30, 2006 as
+filed with the SEC on November 14, 2006. 
+10.24 
+Registration Rights Agreement dated
+September 28, 2006 by and among the registrant and Special Situations
+Fund III QP, L.P., Special Situations Fund III, L.P., Special Situations
+Cayman Fund, L.P. and Special Situations Private Equity Fund, L.P. 
+Exhibit 10.2 to the registrant’s Quarterly
+Report on Form 10-Q for the quarter ended September 30, 2006 as
+filed with the SEC on November 14, 2006. 
+10.25+ 
+National Intelligent Transportation Systems (ITS)
+Architecture Evolution and Support Award/Contract effective as of
+October 1, 2006 by and between the registrant and the Federal Highway
+Administration 
+Exhibit 10.3 to the registrant’s Quarterly
+Report on Form 10-Q for the quarter ended September 30, 2006 as
+filed with the SEC on November 14, 2006. 
+10.26 
+Loan and Security Agreement effective as of
+October 16, 2006 by and between the registrant and Silicon Valley Bank 
+Exhibit 10.4 to the registrant’s Quarterly
+Report on Form 10-Q for the quarter ended September 30, 2006 as
+filed with the SEC on November 14, 2006. 
+10.27 
+Intellectual Property Security Agreement dated
+October 9, 2006 by and between the registrant and Silicon Valley Bank 
+Exhibit 10.5 to the registrant’s Quarterly
+Report on Form 10-Q for the quarter ended September 30, 2006 as
+filed with the SEC on November 14, 2006. 
+10.28+ 
+Settlement Agreement, effective August 15,
+2006, by and between the registrant and Delta Networks, Inc. 
+Exhibit 10.1 to the registrant’s Current
+Report on Form 8-K as filed with the SEC on August 21, 2006 
+10.29* 
+Offer letter effective February 28, 2007 by and
+between the registrant and Abbas Mohaddes 
+Exhibit 10.1 to the registrant’s Current
+Report on Form 8-K as filed with the SEC on March 6, 2007 
+10.30* 
+Separation Agreement and Release of Claims dated
+March 1, 2007 by and between the registrant and Jack Johnson 
+Exhibit 10.2 to the registrant’s Current
+Report on Form 8-K as filed with the SEC on March 6, 2007 
+10.31 
+Sublease Agreement, dated September 30, 2003,
+by and between Odetics, Inc. and Maij, Inc. 
+Exhibit 10.1 to the registrant’s Quarterly
+Report on Form 10-Q for the quarter ended June 30, 2007 as filed
+with the SEC on August 14, 2007 
+10.32 
+Office Lease Agreement, dated May 24, 2007, by
+and between Crown Carnegie Associates, LLC and Iteris, Inc. 
+Exhibit 10.2 to the registrant’s Quarterly
+Report on Form 10-Q for the quarter ended June 30, 2007 as filed
+with the SEC on August 14, 2007 
+Table
+of Contents 
+Exhibit Number 
+Description 
+Where Located 
+10.33 
+Termination Agreement, dated May 30, 2007, by
+and among Transportation Planning Group, Inc., Abbas Mohaddes and
+Iteris, Inc. 
+Exhibit 10.3 to the registrant’s Quarterly
+Report on Form 10-Q for the quarter ended June 30, 2007 as filed
+with the SEC on August 14, 2007 
+10.34* 
+2007 Omnibus Incentive Plan and forms of agreements 
+Appendix A to the registrant’s Definitive Proxy
+Statement on Schedule 14A as filed with the SEC on August 10, 2007 
+10.35 
+Amendment to Loan and Security Agreement, dated
+October 17, 2007, by and between Silicon Valley Bank and
+Iteris, Inc. 
+Exhibit 10.1 to the registrant’s Current
+Report on Form 8-K as filed with the SEC on October 23, 2007 
+10.36 
+Debenture Redemption Agreement, dated
+February 11, 2008, by and among Potomac Capital Partners, LP, Potomac
+Capital International Ltd. and Iteris, Inc. 
+Exhibit 10.1 to the registrant’s Current
+Report on Form 8-K as filed with the SEC on February 15, 2008 
+10.37 
+Debenture Redemption Agreement, dated
+February 27, 2008, by and between Gruber & McBaine
+International and Iteris, Inc. 
+Exhibit 10.1 to the registrant’s Current
+Report on Form 8-K as filed with the SEC on February 29, 2008 
+10.38 
+Debenture Redemption Agreement, dated
+February 27, 2008, by and between Lagunitas Partners, LP and
+Iteris, Inc. 
+Exhibit 10.2 to the registrant’s Current
+Report on Form 8-K as filed with the SEC on February 29, 2008 
+10.39 
+Debenture Redemption Agreement, dated
+February 27, 2008, by and between Jon D. and Linda W. Gruber Trust and
+Iteris, Inc. 
+Exhibit 10.3 to the registrant’s Current
+Report on Form 8-K as filed with the SEC on February 29, 2008 
+10.40* 
+Change in Control Agreement dated June 11, 2008
+by and between James S. Miele and Iteris, Inc. 
+Exhibit 10.42 to the registrant’s Annual
+Report on Form 10-K for the year ended March 31, 2008 as filed with
+the SEC on June 12, 2008 
+10.41 
+Amended and Restated Loan and Security Agreement
+dated February 4, 2009 by and between California Bank & Trust
+and the registrant 
+Exhibit 10.1 to the registrant’s Quarterly
+Report on Form 10-Q for the quarter ended December 31, 2008 as
+filed with the SEC on February 13, 2009 
+10.42 
+Debenture Redemption Agreement, dated
+October 17, 2008, by and between the registrant and certain affiliates
+of Bryant R. Riley 
+Exhibit 10.2 to the registrant’s Quarterly
+Report on Form 10-Q for the quarter ended December 31, 2008 as
+filed with the SEC on February 13, 2009 
+10.43 
+Debenture Redemption Agreement, dated
+October 27, 2008, by and between the registrant and each of Lloyd I.
+Miller, III, Lloyd I. Miller Trust A-4, Milfam I, L.P. and Milfam II,
+L.P. 
+Exhibit 10.3 to the registrant’s Quarterly
+Report on Form 10-Q for the quarter ended December 31, 2008 as
+filed with the SEC on February 13, 2009 
+10.44 
+Debenture Redemption Agreement, dated
+January 9, 2009, by and between the registrant and each of Irvin Kessler
+and Provident Premier Master Fund Ltd. 
+Exhibit 10.4 to the registrant’s Quarterly
+Report on Form 10-Q for the quarter ended December 31, 2008 as
+filed with the SEC on February 13, 2009 
+10.45 
+Separation Agreement and Release of All Claims,
+dated May 20, 2009, by and between Francis Memole and the registrant 
+Filed Herewith 
+21 
+Subsidiaries of the registrant 
+Filed Herewith 
+23 
+Consent of Independent Registered Public Accounting
+Firm 
+Filed Herewith 
+Table
+of Contents 
+Exhibit Number 
+Description 
+Where Located 
+31.1 
+Certification of the Chief Executive Officer
+Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 
+Filed Herewith 
+31.2 
+Certification of the Chief Financial Officer
+Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 
+Filed Herewith 
+32.1 
+Certification of the Chief Executive Officer
+Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
+Section 906 of the Sarbanes-Oxley Act of 2002 
+Filed Herewith 
+32.2 
+Certification of the Chief Financial Officer
+Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
+Section 906 of the Sarbanes-Oxley Act of 2002 
+Filed Herewith 
+* Indicates a management contract or compensatory plan
+or arrangement 
++ Confidential treatment has been requested for
+certain confidential portions of this exhibit pursuant to Rule 24b-2 of
+the Securities Exchange Act of 1934, as amended. In accordance with Rule 24b-2,
+these confidential portions have been omitted from the exhibit and filed
+separately with the SEC.
\ No newline at end of file
diff --git a/raw/filings/0000350868/2008/0001104659-09-037935/filing_metadata.csv b/raw/filings/0000350868/2008/0001104659-09-037935/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..9b1e07f69345022d13e6471218887d85e2894f9c
--- /dev/null
+++ b/raw/filings/0000350868/2008/0001104659-09-037935/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000350868,ITI,"ITERIS, INC.",10-K,2009-06-12,2009-03-31,2009-06-12T15:51:16.000Z,0001104659-09-037935,a09-11714_110k.htm,10-K,2043564,0,0,https://www.sec.gov/Archives/edgar/data/350868/000110465909037935/a09-11714_110k.htm,https://www.sec.gov/Archives/edgar/data/350868/000110465909037935/,2008,2008,1
diff --git a/raw/filings/0000350868/2008/0001104659-09-037935/item1.txt b/raw/filings/0000350868/2008/0001104659-09-037935/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..996a908d5b3e9a0e90d8a65cfb8a07be285f628d
--- /dev/null
+++ b/raw/filings/0000350868/2008/0001104659-09-037935/item1.txt
@@ -0,0 +1,335 @@
+ITEM 1. BUSINESS 
+Overview 
+We are a leader in the
+traffic management market focused on the development and application of
+advanced technologies that reduce traffic congestion and improve the safety of
+surface transportation systems infrastructure. As an added benefit, our
+products and services minimize the environmental impact of traffic congestion.
+By combining outdoor image processing, traffic engineering and information
+technology, we offer a broad range of Intelligent Transportation Systems (“ITS”)
+and driver safety solutions to customers worldwide. 
+We
+were originally incorporated in Delaware in 1987. Our principal executive offices are located
+at 1700 Carnegie Avenue, Santa Ana, California 92705, and our telephone number
+at that location is (949) 270-9400. Our
+Internet website address is www.iteris.com. 
+Our annual reports on Form 10-K, quarterly reports on Form 10-Q
+and current reports on Form 8-K, together with amendments to these
+reports, are available on the “Investors” section of our website, free of
+charge, as soon as reasonably practicable after such material is electronically
+filed with, or furnished to, the Securities and Exchange Commission (“SEC”). The inclusion of our website address in this
+report does not include or incorporate by reference into this report any
+information on our website. 
+We
+currently operate in three reportable segments: Roadway Sensors, Vehicle
+Sensors and Transportation Systems. The Roadway Sensors segment includes our
+Vantage and VersiCam vehicle detection systems for traffic
+intersection control, incident detection and certain highway traffic data
+collection applications. The Vehicle Sensors segment includes our AutoVue Lane
+Departure Warning (“LDW”) system and is comprised of all activities related to
+vehicle safety. The Transportation Systems segment includes transportation
+engineering and consulting services, and the development of transportation
+management and traveler information systems for the ITS industry. See Note 8 of
+the accompanying consolidated financial statements for further details on our
+reportable segments. 
+Our Roadway Sensors
+segment product line uses advanced image processing technology to capture and
+analyze video images through sophisticated algorithms, enabling vehicle
+detection and transmission of both video images and data using a wide range of
+communication technologies. Our Vantage
+video detection systems detect vehicle presence, count, speed, occupancy and
+other traffic data used in traffic management systems. This gives traffic managers the ability to
+mitigate roadway congestion by modifying traffic signal timing or detecting
+incidents quickly. VersiCam, our
+integrated camera and processor video detection system, is a cost-efficient
+video detection system for smaller intersections that require only a few
+detection points. Vantage video
+detection systems have been deployed by hundreds of agencies and are currently
+sold through a network of independent dealers in the United States, Asia, Latin
+America, Europe and the Middle East. 
+Our Vehicle Sensors
+segment addresses the leading cause of roadway fatalities: rear-end, lane change, and roadway departure
+accidents. According to the National
+Highway Traffic Safety Administration, these three crash types result in about
+27,500 of the U.S.’s 42,000 annual traffic fatalities and contribute to a
+considerable economic loss due to injuries, property damage, and decreased
+productivity. 
+2 
+Table of Contents 
+Our Vehicle Sensors
+segment developed the world’s first production LDW system and offers a proven
+system that is available as an original equipment manufacturer (“OEM”) and
+aftermarket option on heavy trucks worldwide and as an OEM option in passenger
+cars. Our LDW products utilize video
+detection images to detect when a vehicle begins to approach an unintended lane
+change. When this occurs, the unit
+automatically emits a distinctive rumble strip or other audible warning sound,
+alerting the driver to make a correction. 
+To date, we have sold approximately 69,000 LDW systems into the heavy
+truck market in Europe, North America and Asia. 
+Our LDW systems are currently qualified as an option on certain heavy
+trucks, including Mercedes-Benz, MAN, Iveco, DAF, Scania, Freightliner and
+FUSO, as well as Neoplan and MAN luxury bus and coach lines. In North America,
+our LDW systems are sold primarily to truck fleets, and to date, 74 U.S. heavy
+truck fleets have selected our LDW systems, with a combined fleet size
+estimated at 58,000 vehicles. Additionally,
+we have licensed our LDW technology to our strategic partner, Valeo Schalter
+and Sensuren GmbH (“Valeo”), an independent automotive supplier, resulting in
+sales to date of approximately 69,000 LDW systems for passenger cars. 
+In addition to our LDW
+systems, we expanded our Vehicle Sensors portfolio in August 2008 with
+newly developed technologies such as radar based Forward Collision Warning (“FCW”)
+and Blind Spot Warning (“BSW”) systems for the North American truck
+market. We also introduced Safety Direct
+in March 2008, which is a system that reports real-time driver performance
+data captured by our LDW system and that has the ability to relay this
+information directly to fleet operators through integration with the truck’s
+existing fleet communications system. We
+offer the FCW and BSW features through the resale of Delphi’s radar based
+systems, for which we are the exclusive North American dealer, while Safety
+Direct was internally developed. These new products, together with our LDW
+products, combine to create a broad suite of active safety driver assistance
+features that help to reduce the number of motor vehicle crashes and the
+severity of crash-related injuries. 
+Our Transportation
+Systems segment includes transportation engineering and consulting services
+focused on the planning, design, development and implementation of
+software-based systems that integrate sensors, video surveillance, computers
+and advanced communications equipment to enable public agencies to monitor,
+control and direct traffic flow, assist in the quick dispatch of emergency
+crews and distribute real-time information about traffic conditions. Our
+services include planning, design and implementation of surface transportation
+infrastructure systems. We perform
+analysis and study goods movement, commercial vehicle operations, travel demand
+forecasting and systems engineering, and identify mitigation measures to reduce
+traffic congestion. These services and
+systems are primarily sold to local, state and national transportation agencies
+in the United States. Our Transportation
+Systems segment is largely dependent upon governmental funding and budgetary
+issues. 
+Sales,
+Marketing and Principal Customers 
+We
+sell our Roadway Sensors products through indirect sales channels comprised of
+independent dealers in the United States and Canada who sell integrated systems
+and related products to the traffic management market, as well as directly to
+the traffic management market using a combination of our own sales personnel
+and an outside sales organization. Our independent dealers are primarily
+responsible for sales, installation and support of these products. These
+dealers maintain an inventory of demonstration traffic products from various
+manufacturers including our vehicle detection systems and sell directly to
+government agencies and installation contractors. These dealers often have
+long-term arrangements with the government agencies in their territory for the
+supply of various products for the construction and renovation of traffic
+intersections. We hold technical training classes for dealers and end users and
+maintain a full-time staff of customer support technicians to provide technical
+assistance when needed. 
+Our marketing strategy
+for our Vehicle Sensors segment is to establish our LDW products as the leading
+platform for in-vehicle video sensing for heavy trucks and passenger cars. We sell LDW systems directly to heavy truck
+manufacturers and to U.S. truck fleets, and our LDW system is currently offered
+as an option on certain heavy trucks, including Mercedes-Benz, MAN, Iveco, DAF,
+Scania, Freightliner and FUSO, as well as Neoplan and MAN luxury bus and coach
+lines. We market the licensing of our LDW technology to manufacturers of
+passenger automobiles through an exclusive strategic relationship with Valeo.
+In connection with this marketing effort, we provide specific contract
+engineering services, technical marketing and sales support to Valeo, which to
+date has enabled the launch of our LDW technology on three Infiniti car
+platforms. We plan to continue to provide technical marketing and sales support
+to Valeo in our efforts to win new OEM customers for the passenger car market
+as well as contract engineering services related to the possible launch of new
+platforms that include our LDW system. 
+We market and sell our
+Transportation Systems services directly to government agencies pursuant to
+negotiated contracts that involve competitive bidding and specific
+qualification requirements. Most of our Transportation Systems contracts are
+with federal, state and municipal customers and generally provide for
+cancellation or renegotiation at the option of the customer upon reasonable
+notice and fees paid for modification. We use selected members of our
+engineering team divided on a regional basis to serve in sales and business development
+functions. We have historically not engaged in sales of transportation
+management systems and traveler information services outside of the U.S., but
+may do so in the future. Our Transportation Systems contracts generally involve
+long lead times and require extensive specification development, evaluation and
+price negotiations. 
+A large portion of our
+revenues are derived from sales to federal, state and local government
+agencies. We currently have a diverse
+customer base with no individual customer representing greater than 10% of our
+total net sales and contract revenues in the fiscal year ended March 31,
+2009 (“Fiscal 2009”) or the fiscal year ended March 31, 2008 (“Fiscal 2008”).
+Also refer to Note 8 of Notes to Consolidated Financial Statements, included
+in Part IV, Item 15 of this report. 
+3 
+Table of Contents 
+Manufacturing
+and Materials 
+We use contract
+manufacturers to build subassemblies that are used in our sensors products.
+Additionally, we procure certain components from qualified suppliers, both
+globally and locally, and generally use multi-sourcing strategies when
+technically and economically feasible to mitigate supply risk. These
+subassemblies and components are delivered to our Santa Ana facility where they
+go through final assembly and testing prior to shipment to our customers.
+Certain of our key suppliers include SMS Technologies, Inc., Hitachi
+American Ltd-UB and Total Electronics LLC. Our manufacturing activities are
+conducted in approximately 9,000 square feet of space at our Santa Ana,
+California facility. Production volume at our subcontractors is based upon
+quarterly forecasts that we adjust on a monthly basis to control inventory
+levels. For LDW products sales to the passenger car market, all manufacturing
+has been and is expected to be performed by Valeo; however, we plan to continue
+to provide engineering support to Valeo. We currently do not manufacture any of
+the hardware used in the transportation management and traveler information
+systems that we design and implement. Our production facility is currently ISO
+9001 certified. 
+Customer
+Support and Services 
+We provide warranty
+service and support for our products, as well as follow-up service and support
+for which we charge separately. Service revenue accounted for less than 1.0% of
+total net sales and contract revenues for Fiscal 2009. We believe customer
+support is a key competitive factor. 
+Backlog 
+Our backlog of
+unfulfilled firm orders was approximately $36.3 million as of March 31,
+2009, which was comprised of $1.0 million related to Roadway Sensors, $800,000
+related to Vehicle Sensors and $34.5 million related to Transportation Systems.
+Substantially all of the backlog for Roadway Sensors and Vehicle Sensors is
+expected to be recognized as revenue in the fiscal year ending March 31,
+2010 (“Fiscal 2010”), while approximately 75% of Transportation Systems backlog
+is expected to be recognized as revenue in Fiscal 2010. At March 31, 2008,
+we had backlog of approximately $26.8 million, which was comprised of $900,000
+related to Roadway Sensors, $1.3 million related to Vehicle Sensors and $24.6
+million related to Transportation Systems. All backlog as of March 31,
+2008 for Roadway Sensors and Vehicle Sensors was recognized as revenue in
+Fiscal 2009 while approximately 65% of our March 31, 2008 backlog for
+Transportation Systems was recognized as revenue in Fiscal 2009. Pursuant to
+the customary terms of our agreements with government contractors and other
+customers, customers can generally cancel or reschedule orders with little
+or no penalties. Lead times for the release of purchase orders often depend
+upon the scheduling and forecasting practices of our individual customers,
+which also can affect the timing of the conversion of our backlog into
+revenues. For these reasons, among others, our backlog at a particular date may
+not be indicative of our future revenues, in particular for Roadway Sensors and
+Vehicle Sensors. 
+Product
+Development 
+Most of our development
+activities are conducted at our principal facilities in Santa Ana, California.
+Our company-sponsored research and development costs and expenses were
+approximately $4.0 million for Fiscal 2009, $3.6 million for Fiscal 2008, and
+$4.0 million for the fiscal year ended March 31, 2007 (“Fiscal 2007”). We
+expect to continue to pursue certain product development programs and incur
+research and development expenditures. 
+Competition 
+We generally face significant
+competition in each of our target markets. Increased competition may result in
+price reductions, reduced gross margins and loss of market share, any of which
+could have a material adverse effect on our business, financial condition and
+results of operations. While our LDW products have historically been the only
+established commercially-available LDW system used in the U.S. and in Europe in
+the heavy truck market, we have recently experienced increased competition from
+new competitors in this market. We consider competitors in this market to
+include Delphi Automotive Systems Corporation, NEC Corporation and Hitachi Ltd.
+in Japan and Robert Bosch GmbH in Europe, Continental Tavis, Visteon and
+Takata, which currently have developed or are developing video sensor
+technologies for the vehicle industry that could be used for lane departure
+warning systems. In the market for our Roadway Sensors vehicle detection
+products, we compete with manufacturers of other above ground video camera
+detection systems such as Econolite Control Products, Inc., Traficon,
+N.V., and other non-intrusive detection devices including microwave, infrared,
+ultrasonic and magnetic detectors, as well as manufacturers and installers of
+in-pavement inductive loop products. 
+The Transportation
+Systems market is highly fragmented and is subject to evolving national and
+regional quality and safety standards. Our competitors vary in number, scope
+and breadth of the products and services they offer. Our competitors in
+advanced Transportation Systems include national corporations such as
+Transcore, Siemens, Telvent Farradyne, Kimley-Horn and Associates, Inc.
+and Delcan. Our competitors in transportation engineering, planning and design
+include major firms such as Parsons Brinkerhoff, Inc., URS, HNTB and
+Parsons Transportation Group, Inc., as well as many smaller regional
+engineering firms. 
+4 
+Table of Contents 
+In general, the markets
+for the products and services we offer are highly competitive and are
+characterized by rapidly changing technology and evolving standards. Many of
+our current and prospective competitors have longer operating histories,
+greater name recognition, access to larger customer bases and significantly
+greater financial, technical, manufacturing, distribution and marketing
+resources than us. As a result, they may be able to adapt more quickly to new
+or emerging standards or technologies or to devote greater resources to the
+promotion and sale of their products. It is also possible that new competitors
+or alliances among competitors could emerge and rapidly acquire significant
+market share. We believe that our ability to compete effectively in our target
+markets will depend on a number of factors, including the success and timing of
+our new product development, the compatibility of our products with a broad
+range of computing systems, product quality and performance, reliability,
+functionality, price and service and technical support. Our failure to provide
+services and develop and market products that compete successfully with those
+of other suppliers and consultants in our target markets would have a material
+adverse effect on our business, financial condition and results of operations. 
+Intellectual
+Property and Proprietary Rights 
+Our ability to compete
+effectively depends in part on our ability to develop and maintain the
+proprietary aspects of our technology. Our policy is to obtain appropriate
+proprietary rights protection for any potentially significant new technology
+acquired or developed by us. We currently hold ten U.S. patents, which expire
+commencing in 2012, relating to our outdoor image processing techniques used in
+our AutoVue LDW systems. Nine of our patents relate specifically to our LDW
+technology and provide a basis for enhanced functionality for rain sensing and
+improved performance. We believe that our other patent, while important for our
+technology platforms, is less critical to our near term product strategy. In April 2009, we acquired the rights to
+U.S., Canadian, and European Community patent applications for an Electronic
+Traffic Monitor that is related to new products in our Roadway Sensors
+businesses (also refer to Note 10 of Notes to Consolidated Financial
+Statements, included in Part IV, Item 15 of this report). We cannot
+assure you that any new patents will be granted pursuant to these or subsequent
+applications. 
+In addition to patent
+laws, we rely on copyright and trade secret laws to protect our proprietary
+rights. We attempt to protect our trade secrets and other proprietary
+information through agreements with customers and suppliers, proprietary
+information agreements with our employees and consultants, and other similar
+measures. We do not have any material licenses or trademarks other than those
+relating to product names. We cannot be certain that we will be successful in
+protecting our proprietary rights. While we believe our patents, patent
+applications, software and other proprietary know-how have value, changing
+technology makes our future success dependent principally upon our employees’
+technical competence and creative skills for continuing innovation. 
+Litigation may be
+necessary in the future to enforce our proprietary rights, to determine the
+validity and scope of the proprietary rights of others, or to defend us against
+claims of infringement or invalidity by others. An adverse outcome in such
+litigation or similar proceedings could subject us to significant liabilities
+to third parties, require disputed rights to be licensed from others or require
+us to cease marketing or using certain products, any of which could have a
+material adverse effect on our business, financial condition and results of
+operations. In addition, the cost of addressing any intellectual property
+litigation claim, both in legal fees and expenses, as well as from the
+diversion of management’s resources, regardless of whether the claim is valid,
+could be significant and could have a material adverse effect on our business,
+financial condition and results of operations. 
+Employees 
+We refer to our employees
+as associates. As of June 1, 2009, we employed an aggregate of 242
+associates, including 55 associates in general management, administration and
+finance; 22 associates in sales and marketing; 132 associates in engineering
+and product development; 20 associates in operations, manufacturing and
+quality; and 13 associates in customer service. None of our associates are
+represented by a labor union, and we have never experienced a work stoppage. 
+Government
+Regulation 
+Our manufacturing
+operations are subject to various federal, state and local laws and
+regulations, including those restricting the discharge of materials into the
+environment. We are not involved in any pending or, to our knowledge,
+threatened governmental proceedings, which would require curtailment of our
+operations because of such laws and regulations. We continue to expend funds in
+connection with our compliance with applicable environmental regulations. These
+expenditures have not, however, been significant in the past, and we do not
+expect any significant expenditure in the near future. Currently, compliance
+with foreign laws has not had a material impact on our business and is not expected
+to have a material impact in the near future.
\ No newline at end of file
diff --git a/raw/filings/0000350868/2008/0001104659-09-037935/item13.txt b/raw/filings/0000350868/2008/0001104659-09-037935/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..394f83aecc03ae845af1cb6b1bfe4d5f4ba9b06a
--- /dev/null
+++ b/raw/filings/0000350868/2008/0001104659-09-037935/item13.txt
@@ -0,0 +1,8 @@
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
+DIRECTOR INDEPENDENCE 
+The information under the
+captions “Corporate Governance — Director Independence” and “Certain
+Transactions,” appearing in our proxy statement for the 2009 Annual Meeting of
+Stockholders, is incorporated herein by reference. 
+28 
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0000350868/2008/0001104659-09-037935/item9a.txt b/raw/filings/0000350868/2008/0001104659-09-037935/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..7fc5dcba2c6b98e1aba2b7bda8bd5b8ede178718
--- /dev/null
+++ b/raw/filings/0000350868/2008/0001104659-09-037935/item9a.txt
@@ -0,0 +1,68 @@
+ITEM 9A. CONTROLS AND PROCEDURES 
+(a) Evaluation of disclosure controls and
+procedures. In accordance with Rule 13a-15(b) of
+the Securities Exchange Act of 1934, as of the end of the period covered by
+this Annual Report on Form 10-K, management evaluated, with the
+participation of the our President and Chief Executive Officer and the Chief
+Financial Officer, the effectiveness of the design and operation of our
+disclosure controls and procedures (as defined in Rule 13a-15(e) under
+the Exchange Act). Based upon their evaluation of these disclosure controls and
+procedures, the President and Chief Executive Officer and the Chief Financial
+Officer have concluded that our disclosure controls and procedures were
+effective as of the date of such evaluation in ensuring that information
+required to be disclosed in our Exchange Act reports is (1) recorded,
+processed, summarized and reported in a timely manner, and (2) accumulated
+and communicated to management, including the Company’s President and Chief
+Executive Officer and the Chief Financial Officer, as appropriate, to allow
+timely decisions regarding required disclosure. 
+(b) 
+Changes in internal control. There was no
+change in our internal control over financial reporting that occurred during
+the period covered by this Annual Report on Form 10-K that has materially
+affected, or is reasonably likely to materially affect, our internal control
+over financial reporting. 
+Inherent Limitations on Internal
+Control 
+A control system, no
+matter how well conceived and operated, can provide only reasonable, not
+absolute, assurance that the objectives of the control system are met. Further,
+the benefits of controls must be considered relative to their costs. Because of
+the inherent limitations in all control systems, no evaluation of controls can
+provide absolute assurance that all control issues and instances of management
+override or improper acts, if any, have been detected. These inherent
+limitations include the realities that judgments in decision making can be
+faulty, and that breakdowns can occur because of simple errors. Additionally,
+controls can be circumvented by the individual acts of some persons, by
+collusion of two or more people, or by management override of the control. The
+design of any system of controls is also based in part upon certain assumptions
+about the likelihood of future events, and there can be no assurance that any
+design will succeed in achieving its stated goals under all potential future
+conditions. Because of the inherent limitations in a cost-effective control
+system, misstatements due to management override, error or improper acts may
+occur and not be detected. Any resulting misstatement or loss may have an
+adverse and material effect on our business, financial condition and results of
+operations. 
+27 
+Table of Contents 
+Management’s Report on Internal
+Control Over Financial Reporting 
+Our management is
+responsible for establishing and maintaining adequate internal control over
+financial reporting. Our internal control system was designed to provide
+reasonable assurance to management and the board of directors regarding the
+effectiveness of our internal control processes over the preparation and fair
+presentation of published financial statements. 
+We have assessed the
+effectiveness of our internal controls over financial reporting as of March 31,
+2009. In making this assessment, we used the criteria set forth by the
+Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in
+Internal Control—Integrated Framework. Based on our assessment, we believe
+that, as of March 31, 2009, our internal control over financial reporting
+is effective based on those criteria. 
+This annual report does
+not include an attestation report of our independent registered public
+accounting firm regarding internal control over financial reporting. Management’s
+report was not subject to attestation by our independent registered public
+accounting firm pursuant to the rules of the Securities and Exchange
+Commission that permit us to provide only management’s report in this annual
+report.
\ No newline at end of file
diff --git a/raw/filings/0000350868/2008/0001104659-09-037935/rp_note.txt b/raw/filings/0000350868/2008/0001104659-09-037935/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000350868/2008/0001104659-09-037935/rpt_disclosure.txt b/raw/filings/0000350868/2008/0001104659-09-037935/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000350868/2009/0001104659-10-029895/filing.txt b/raw/filings/0000350868/2009/0001104659-10-029895/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..c8a4d9a39d2001ee21b05a00c23679354ac2bef7
--- /dev/null
+++ b/raw/filings/0000350868/2009/0001104659-10-029895/filing.txt
@@ -0,0 +1,6399 @@
+10-K
+1
+a10-10572_110k.htm
+10-K
+Table of
+Contents 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+(Mark One) 
+x 
+ANNUAL
+REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
+ACT OF 1934 
+For the fiscal year ended
+March 31, 2010 
+OR 
+o 
+TRANSITION
+REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
+ACT OF 1934 
+For the transition period from
+to
+Commission file number 001-08762 
+ITERIS, INC. 
+(Exact Name of Registrant as Specified in Its Charter) 
+Delaware 
+95-2588496 
+(State or Other
+Jurisdiction 
+of Incorporation or Organization) 
+(I.R.S. Employer 
+Identification No.) 
+1700 Carnegie Ave., Santa Ana, California 92705 
+(Address of Principal Executive Offices) (Zip Code) 
+Registrant’s Telephone Number, Including Area Code: (949) 270-9400 
+Securities
+registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Name of each exchange on which registered 
+Common Stock, $0.10 par
+value 
+NYSE Amex 
+Securities registered
+pursuant to Section 12(g) of the Act: None 
+Indicate by check mark if the
+registrant is a well-known seasoned issuer, as defined in Rule 405 of the
+Securities Act. Yes o No x 
+Indicate by check mark if the registrant is not required to file reports
+pursuant to Section 13 or Section 15(d) of the Act. Yes o No x 
+Indicate by check mark whether the registrant (1) has filed all
+reports required to be filed by Section 13 or 15(d) of the Securities
+Exchange Act of 1934 during the preceding 12 months (or for such shorter period
+that the registrant was required to file such reports), and (2) has been
+subject to such filing requirements for the past 90 days. Yes x No o 
+Indicate by a check mark if disclosure of delinquent filers pursuant to
+Item 405 of Regulation S-K is not contained herein, and will not be contained,
+to the best of registrant’s knowledge, in definitive proxy or information
+statements incorporated by reference in Part III of this Form 10-K or
+any amendment to this Form 10-K. o 
+Indicate by check mark
+whether the registrant has submitted electronically and posted on its corporate
+Web site, if any, every Interactive Data File required to be submitted and
+posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter)
+during the preceding 12 months (or for such shorter period that the registrant
+was required to submit and post such files). 
+Yes o No o 
+Indicate by check mark whether the registrant is a
+large accelerated filer, an accelerated filer, a non-accelerated filer, or a
+smaller reporting company. See definitions of “large accelerated filer,” “accelerated
+filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
+(Check one): 
+Large accelerated filer o 
+Accelerated filer o 
+Non-accelerated filer o 
+Smaller reporting company x 
+(Do not check if a smaller reporting company) 
+Indicate by check mark whether the registrant is a shell company (as
+defined in Exchange Act Rule 12b-2). Yes o No x 
+Based on the closing sale price of the registrant’s common stock on the
+last business day of the registrant’s most recently completed second fiscal
+quarter, the aggregate market value of the voting common stock held by
+nonaffiliates of the registrant was approximately $32,703,000. For the purposes
+of this calculation, shares owned by officers, directors and 10% stockholders
+known to the registrant have been deemed to be owned by affiliates. This
+determination of affiliate status is not necessarily a conclusive determination
+for other purposes. 
+As of May 14, 2010, there were 34,331,756 shares of our common
+stock outstanding. 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Part III incorporates by reference certain information from the
+registrant’s definitive proxy statement for the 2010 Annual Meeting of
+Stockholders, which will be filed with the Securities and Exchange Commission
+not later than 120 days after the end of the fiscal year ended March 31,
+2010. Except with respect to information specifically incorporated by reference
+in this report, the registrant’s proxy statement is not deemed to be filed as a
+part hereof. 
+Table of Contents 
+ITERIS, INC. 
+ANNUAL REPORT ON FORM 10-K 
+FOR THE FISCAL YEAR ENDED MARCH 31, 2010 
+TABLE OF
+CONTENTS 
+PART I 
+ITEM 1. 
+BUSINESS 
+2 
+ITEM 1A. 
+RISK FACTORS 
+6 
+ITEM
+1B. 
+UNRESOLVED
+STAFF COMMENTS 
+15 
+ITEM 2. 
+PROPERTIES 
+15 
+ITEM 3. 
+LEGAL
+PROCEEDINGS 
+15 
+ITEM 4. 
+(REMOVED AND
+RESERVED) 
+15 
+PART II 
+16 
+ITEM
+5. 
+MARKET FOR
+REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
+PURCHASES OF EQUITY SECURITIES 
+16 
+ITEM 6. 
+SELECTED
+FINANCIAL DATA 
+16 
+ITEM
+7. 
+MANAGEMENT’S
+DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+16 
+ITEM
+7A. 
+QUANTITATIVE
+AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
+29 
+ITEM
+8. 
+FINANCIAL
+STATEMENTS AND SUPPLEMENTARY DATA 
+29 
+ITEM
+9. 
+CHANGES IN AND
+DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+29 
+ITEM
+9A(T). 
+CONTROLS
+AND PROCEDURES 
+30 
+ITEM 9B. 
+OTHER
+INFORMATION 
+30 
+PART III 
+30 
+ITEM
+10. 
+DIRECTORS,
+EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+30 
+ITEM 11. 
+EXECUTIVE
+COMPENSATION 
+31 
+ITEM
+12. 
+SECURITY
+OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
+STOCKHOLDER MATTERS 
+31 
+ITEM
+13. 
+CERTAIN
+RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+31 
+ITEM
+14. 
+PRINCIPAL
+ACCOUNTING FEES AND SERVICES 
+31 
+PART IV 
+31 
+ITEM
+15. 
+EXHIBITS
+AND FINANCIAL STATEMENT SCHEDULES 
+31 
+Unless
+otherwise indicated in this report, the “Company,” “we,” “us” and “our” refer
+to Iteris, Inc. and our wholly-owned subsidiary, Iteris Europe, GmbH. 
+AutoVue ® , Iteris ® ,
+Vantage ® , VantageView™, VersiCam™, SafetyDirect™ and Abacus™ are among the
+trademarks of Iteris, Inc. Any other trademarks or trade names mentioned
+herein are the property of their respective owners. 
+1 
+Table of Contents 
+Cautionary
+Statement 
+This report, including the following discussion and analysis, contains
+forward-looking statements (within the meaning of the Private Securities
+Litigation Reform Act of 1995) that are based on our current expectations,
+estimates and projections about our business and our industry, and reflect
+management’s beliefs and certain assumptions made by us based upon information
+available to us as of the date of this report. When used in this report and the
+information incorporated herein by reference, the words “expect(s),” “feel(s),”
+“believe(s),” “should,” “would,” “could,” “may,” “anticipate(s),” “estimate(s)”
+and similar expressions or variations of these words are intended to identify
+forward-looking statements. These forward-looking statements include but are
+not limited to statements regarding our anticipated sales, revenue, expenses,
+profits, capital needs, competition, backlog and manufacturing capabilities,
+the practical market applications, future applications and acceptance of our
+products and services, the status of our facilities and product development.
+These statements are not guarantees of future performance and are subject to
+certain risks and uncertainties which could cause actual results to differ
+materially from those projected. You should not place undue reliance on these
+forward-looking statements that speak only as of the date hereof. We undertake
+no obligation to republish revised forward-looking statements to reflect events
+or circumstances after the date hereof or to reflect the occurrence of
+unanticipated events. We encourage you to carefully review and consider the
+various disclosures made by us which describe certain factors which could
+affect our business, including those in “ Risk Factors”
+in Item 1A of this report, before deciding to invest in our company or to
+maintain or increase your investment. We undertake no obligation to revise or
+update publicly any forward-looking statement for any reason. 
+PART I 
+ITEM 1. BUSINESS 
+Overview 
+We are a leader in the
+traffic management market focused on the development and application of
+advanced technologies that reduce traffic congestion and improve the safety of
+surface transportation systems infrastructure. Additionally, we believe that
+our products and services, as well as sound traffic management, minimize the
+environmental impact of traffic congestion. By combining outdoor image
+processing, traffic engineering and information technology, we offer a broad
+range of Intelligent Transportation Systems (“ITS”) and driver safety solutions
+to customers worldwide. 
+We were originally incorporated in Delaware in 1987.
+Our principal executive offices are located at 1700 Carnegie Avenue, Santa Ana,
+California 92705, and our telephone number at that location is (949) 270-9400.
+Our Internet website address is www.iteris.com. Our annual reports on Form 10-K,
+quarterly reports on Form 10-Q and current reports on Form 8-K,
+together with amendments to these reports, are available on the “Investors”
+section of our website, free of charge, as soon as reasonably practicable after
+such material is electronically filed with, or furnished to, the Securities and
+Exchange Commission (“SEC”). The inclusion of our website address in this
+report does not include or incorporate by reference into this report any
+information on our website. 
+Products
+and Services 
+We currently operate in
+three reportable segments: Roadway Sensors, Vehicle Sensors and Transportation
+Systems. The Roadway Sensors segment includes, among other products, our
+Vantage, Versicam and Pico vehicle detection systems for traffic
+intersection control, incident detection and certain highway traffic data
+collection applications. The Vehicle Sensors segment includes our lane
+departure warning (“LDW”) products, including our AutoVue LDW system, and is
+comprised of all activities related to in-vehicle safety. The Transportation
+Systems segment includes transportation engineering and consulting services,
+and the development of transportation management and traveler information
+systems for the ITS industry. See Note 10 of Notes to Consolidated Financial
+Statements, included in Part IV, Item 15 of this report, for further
+details on our reportable segments. 
+Roadway Sensors. Our Roadway Sensors segment product line
+uses advanced image processing technology to capture and analyze video images
+through sophisticated algorithms, enabling vehicle detection and transmission
+of both video images and data using a wide range of communication technologies.
+Our Vantage video detection systems detect vehicle presence, count, speed,
+occupancy and other traffic data used in traffic management systems. Our
+Vantage systems give traffic managers the ability to mitigate roadway
+congestion by modifying traffic signal timing or detecting incidents quickly.
+Our VantageView software supplements our Vantage video detection systems by
+providing an integrated platform to manage and “see” video detection assets
+remotely over a network connection. Vantage video detection systems have been
+deployed by hundreds of agencies and are currently sold through a network of
+independent dealers in the United States (“U.S.”), Asia, Latin America, Europe
+and the Middle East. VersiCam, our integrated camera and processor video
+detection system, is a cost-efficient video detection system for smaller
+intersections that require only a few detection points. In December 2009,
+we introduced Pico, a compact video detection system that delivers superior
+vehicle detection in a small and economical framework, and was developed
+primarily to address international video detection needs. We anticipate that
+future growth domestically and internationally, particularly in developing
+countries, will be dependent in part on the continued adoption of above-ground
+video detection technologies, instead of in-pavement loop technology, to manage
+traffic. 
+2 
+Table of Contents 
+Our Roadway Sensors
+product line also includes the Abacus family of products, which has been
+designed with a blend of artificial intelligence and video detection algorithms
+that allow either fixed or pan-tilt-zoom cameras to be used for data collection
+and incident detection. Our Abacus products take advantage of the large number
+of existing installed closed-circuit television video feeds monitoring
+roadways, tunnels and bridges and at signalized intersections. This flexibility
+of using a broad range of cameras with an appropriate perspective allows for
+accurate data collection without the set-up and calibration required with other
+systems. 
+Vehicle Sensors. Our Vehicle Sensors segment addresses
+the leading causes of roadway fatalities: lane change, roadway departure and
+rear-end collision accidents. According to the National Highway Traffic Safety
+Administration (“NHTSA”), these three crash types result in more than 60% of
+the U.S.’s annual traffic fatalities and contribute to a considerable economic
+loss due to injuries, property damage, and decreased productivity. Early
+estimates by the NHTSA of motor vehicle traffic fatalities in 2009 were
+approximately 34,000. 
+We
+developed the world’s first production LDW system and offer a proven system
+that is available as an original equipment manufacturer (“OEM”) and aftermarket
+option on heavy trucks worldwide and as an option in certain passenger cars.
+Our LDW products utilize video detection images to detect when a vehicle begins
+to drift toward an unintended lane change. When this occurs, the unit
+automatically emits a distinctive rumble strip or other audible warning sound,
+alerting the driver to make a correction. To date, we have sold approximately
+79,000 LDW systems into the heavy truck market in Europe, North America and
+Asia. Our LDW systems are currently qualified as an option on certain heavy
+trucks, including Mercedes-Benz, MAN, Iveco, DAF, Scania, Freightliner and
+FUSO, as well as Neoplan and MAN luxury bus and coach lines. In North America,
+our LDW systems are sold primarily to truck fleets. 
+In March 2009,
+the European Union (“EU”) approved a mandate that sets better standards to
+improve road safety in Europe. The new mandated rules for safety
+technology includes systems such as electronic stability control, advanced
+emergency braking and LDW systems to be compulsory on heavy-duty trucks and
+buses to further reduce accident risks. LDW systems are expected to
+be mandatory in Europe on all new heavy truck models beginning in
+2013. We believe that in order for the 2013 EU mandate
+for active safety systems to have a positive impact on our sales, we need to
+establish long-term supplier agreements with our European OEM heavy truck
+customers. To date we have agreements to supply certain of our European heavy
+truck customers through 2012 and we are actively working on agreements with
+other heavy truck OEMs that extend through 2013 and beyond in order to meet the
+anticipated increase in demand. However, we cannot assure you that our efforts
+will be successful or that the expected increase in demand will occur. We believe that
+the expected 2013 EU mandate for LDW and other active safety systems, and an
+increasing overall awareness of the potential benefits of LDW, helps validate
+the long-term market opportunity for LDW systems in commercial vehicles. Additionally, in North America we plan to develop
+partnerships with other manufacturers and suppliers of safety devices for heavy
+trucks to jointly sell our LDW systems and provide our SafetyDirect software
+tool to North American trucking fleets. 
+We
+have entered into an exclusive license of our LDW technology to our strategic
+partner, Valeo Schalter and Sensuren GmbH (“Valeo”), for the passenger car
+market, resulting in sales to date of approximately 79,300 LDW systems for
+passenger cars. We and our partner have recently experienced a greater degree
+of competition in the passenger car market as several passenger car OEMs have
+introduced vehicle platforms with competing LDW systems. However, Valeo continues
+to pursue opportunities in the passenger car market. 
+In addition to our LDW systems, our Vehicle Sensors
+portfolio includes radar-based Forward Collision Warning (“FCW”) and Blind Spot
+Warning (“BSW”) systems for the North American truck market. We offer the FCW
+and BSW features through the resale of Delphi’s radar based systems, for which
+we are the exclusive North American dealer. Our portfolio also includes our
+internally-developed SafetyDirect software system, which can provide a single
+point of access to monitor and synchronize driver performance data on braking,
+stability control, following distances, and lane departure warnings for
+individual drivers as well as entire fleets. SafetyDirect uses information
+transmitted from the vehicle by the fleet’s onboard mobile communications
+system to provide fleet operators with a comprehensive view of the entire
+fleet, as well as the ability to drill down to detailed information on
+individual drivers and events. These products, together with our LDW products,
+combine to create a broad suite of active safety driver assistance features
+designed to help reduce the number of motor vehicle crashes and the severity of
+crash-related injuries. 
+Transportation Systems. Our Transportation Systems segment
+includes transportation engineering and consulting services focused on the
+planning, design, development and implementation of software-based systems that
+integrate sensors, video surveillance, computers and advanced communications
+equipment to enable public agencies to monitor, control and direct traffic
+flow, assist in the quick dispatch of emergency crews and distribute real-time
+information about traffic conditions. Our services include planning, design and
+implementation of surface transportation infrastructure systems. We perform
+analysis and study goods movement, commercial vehicle operations, travel demand
+forecasting and systems engineering, and identify mitigation measures to 
+3 
+Table of Contents 
+reduce traffic
+congestion. These services and systems have historically been primarily sold to
+local, state and national transportation agencies in the U.S.; however, during
+the fiscal year ended March 31, 2010 (“Fiscal 2010”), we began work on our
+first overseas contracts in Abu Dhabi and Dubai, and plan to continue to pursue
+additional international business. Our Transportation Systems segment is
+largely dependent upon governmental funding, and is affected by state and local
+budgetary issues. 
+Sales,
+Marketing and Principal Customers 
+We sell our Roadway
+Sensors products through indirect sales channels comprised of a strong network
+of independent dealers in the U.S. and Canada who sell integrated systems and
+related products to the traffic management market, as well as directly to the
+traffic management market using a combination of our own sales personnel and an
+outside sales organization. Our independent dealers are well-trained in, and
+primarily responsible for, sales, installation, set-up and support of our
+products, and maintain an inventory of demonstration traffic products from
+various manufacturers including our vehicle detection systems and sell directly
+to government agencies and installation contractors. These dealers often have
+long-term arrangements with local government agencies in their respective
+territories for the supply of various products for the construction and
+renovation of traffic intersections, and are generally well-known suppliers of
+high-quality ITS products to the traffic management market. We periodically
+hold technical training classes for our dealers and end users and maintain a
+full-time expert staff of customer support technicians throughout the U.S. to
+provide technical assistance when needed. When appropriate, we have the ability
+to modify or make changes to our dealer network to best suit the needs of the
+market and our customer base. In the states where we sell direct, we use our
+own expert staff to sell, oversee installations and set-up issues and support
+our products. 
+Our marketing strategy
+for our Vehicle Sensors segment is to establish our LDW products as the leading
+platform for in-vehicle video sensing for heavy trucks and passenger cars. We
+sell LDW systems directly to heavy truck manufacturers and to U.S. truck
+fleets, and our LDW system is currently offered as an option on certain heavy
+trucks, including Mercedes-Benz, MAN, Iveco, DAF, Scania, Freightliner and
+FUSO, as well as Neoplan and MAN luxury bus and coach lines. We market the
+licensing of our LDW technology to manufacturers of passenger automobiles
+through an exclusive strategic relationship with Valeo. In connection with this
+marketing effort, we provide specific contract engineering services, technical
+marketing and sales support to Valeo, which to date has enabled the launch of
+our LDW technology on three Infiniti car platforms, with a fourth platform
+expected in the summer of 2010. We plan to continue to provide technical
+marketing and sales support to Valeo in our efforts to win new OEM customers
+for the passenger car market, as well as contract engineering services related
+to the possible launch of new platforms that include our LDW system. 
+We market and sell our
+Transportation Systems services directly to government agencies pursuant to
+negotiated contracts that involve competitive bidding and specific
+qualification requirements. Most of our Transportation Systems contracts are
+with federal, state and municipal customers and generally provide for
+cancellation or renegotiation at the option of the customer upon reasonable
+notice and fees paid for modification. We use selected members of our
+engineering team on a regional basis to serve in sales and business development
+functions. Our Transportation Systems contracts generally involve long lead
+times and require extensive specification development, evaluation and price
+negotiations. 
+A large portion of our
+revenues are derived from sales to federal, state and local government
+agencies. We currently have a diverse customer base with no individual customer
+representing greater than 10% of our total net sales and contract revenues in
+Fiscal 2010, or in the fiscal years ended March 31, 2009 (“Fiscal 2009”)
+and March 31, 2008 (“Fiscal 2008”). Also refer to Note 10 of Notes to
+Consolidated Financial Statements, included in Part IV, Item 15 of
+this report. 
+Manufacturing and Materials 
+We use contract
+manufacturers to build subassemblies that are used in our sensors products.
+Additionally, we procure certain components from qualified suppliers, both
+globally and locally, and generally use multi-sourcing strategies when
+technically and economically feasible to mitigate supply risk. These
+subassemblies and components are delivered to our Santa Ana, California facility
+where they go through final assembly and testing prior to shipment to our
+customers. Certain of our key suppliers include CTS Electronics Manufacturing
+Solutions, Inc., SMS Technologies, Inc., Total Electronics LLC and
+Hitachi American Ltd-UB. Our manufacturing activities are conducted in
+approximately 9,000 square feet of space at our Santa Ana facility. Production
+volume at our subcontractors is based upon quarterly forecasts that we
+generally adjust on a monthly basis to control inventory levels. For LDW
+products sales to the passenger car market, all manufacturing has been and is
+expected to be performed by Valeo; however, we plan to continue to provide
+engineering support to Valeo. We typically do not manufacture any of the
+hardware used in the transportation management and traveler information systems
+that we design and implement. Our production facility is currently ISO 9001
+certified. 
+Customer
+Support and Services 
+We provide warranty
+service and support for our products, as well as follow-up service and support
+for which we charge separately. Such service revenue accounted for less than
+1.0% of total net sales and contract revenues for each of Fiscal 2010 and
+Fiscal 2009. We believe customer support is a key competitive factor. 
+4 
+Table of Contents 
+Backlog 
+Our total backlog of
+unfulfilled firm orders was approximately $30.6 million as of March 31,
+2010, which was comprised of $1.6 million related to Roadway Sensors, $600,000
+related to Vehicle Sensors and $28.4 million related to Transportation Systems.
+Substantially all of the backlog for Roadway Sensors and Vehicle Sensors is
+expected to be recognized as revenue in the fiscal year ending March 31,
+2011 (“Fiscal 2011”). We have historically recognized in the subsequent fiscal
+year between 50% to 70% of our fiscal year end Transportation Systems backlog,
+and currently expect that trend to continue for Fiscal 2011. The timing and
+realization of this backlog is subject to the inherent uncertainties of doing
+business with federal, state and local governments, particularly in view of
+budgetary constraints, cut-backs and other delays or reallocations of funding
+that these entities typically face. 
+Pursuant to the customary
+terms of our agreements with government contractors and other customers,
+customers can generally cancel or reschedule orders with little or no
+penalties. Lead times for the release of purchase orders often depend upon the
+scheduling and forecasting practices of our individual customers, which also
+can affect the timing of the conversion of our backlog into revenues. For these
+reasons, among others, our backlog at a particular date may not be indicative
+of our future revenues, in particular for our Roadway Sensors and Vehicle
+Sensors segments. 
+Product
+Development 
+Most of our product
+development activities are conducted at our principal facilities in Santa Ana.
+Our research and development costs and expenses were approximately $3.7 million
+for Fiscal 2010, $4.0 million for Fiscal 2009 and $3.6 million for Fiscal 2008.
+We expect to continue to pursue various product development programs and incur
+research and development expenditures in future periods. 
+We
+believe our engineering and product development capabilities are a competitive
+strength. We strive to continue to develop new products to meet the needs of
+the ever-changing ITS market as well as enhance and refine our existing product
+lines. Within the last twelve months we have introduced our VersiCam and
+VersiCam wireless products, Pico, Abacus and our new RZ-4 Advanced camera, as
+well as our RZ-4 Advanced Wide Dynamic Range camera, which significantly
+improves video detection performance in certain harsh lighting conditions. We
+believe that developing new offerings across our segments and enhancing,
+refining and marketing our existing products is a key component of strong
+organic growth and profitability. 
+Competition 
+We generally face
+significant competition in each of our target markets. Increased competition
+may result in price reductions, reduced gross margins and loss of market share,
+any of which could have a material adverse effect on our business, financial
+condition and results of operations. 
+In the market for our
+Roadway Sensors vehicle detection products, we compete with manufacturers and
+distributors of other above ground video camera detection systems such as Peek
+Traffic Corporation, Wavetronix LLC, Econolite Control Products, Inc.,
+Traficon, N.V., Image Sensing Systems, Inc. and other non-intrusive
+detection devices including microwave, infrared, ultrasonic and magnetic
+detectors, as well as manufacturers and installers of in-pavement inductive
+loop products, which have historically, and currently continue to be, the
+predominant detection system in this market. 
+In the market for our
+Vehicle Sensors systems, we believe that as a result of the expected 2013
+European mandate for LDW and other active safety systems, and an overall
+awareness of the potential benefits of LDW, that we will experience an even
+higher degree of competition from a variety of tier-one OEM suppliers and other
+potential market entrants, worldwide. Additionally, we and our strategic
+partner (Valeo) have recently experienced a greater degree of competition in
+the passenger car market as several passenger car OEMs have introduced vehicle
+platforms with competing LDW systems. We consider competitors in this market to
+include Delphi Automotive Systems Corporation, NEC Corporation and Hitachi Ltd.
+in Japan and Robert Bosch GmbH in Europe, Continental Tavis, Visteon and
+Takata, all of which currently have developed or are developing video sensor
+technologies for the vehicle industry that could be used for lane departure
+warning systems. 
+The Transportation
+Systems market is highly fragmented and is subject to evolving national and
+regional quality and safety standards. Our competitors vary in number, scope
+and breadth of the products and services they offer. Our competitors in
+advanced Transportation Systems include national corporations such as
+Transcore, Siemens, Telvent Farradyne, Kimley-Horn and Associates, Inc.
+and Delcan. Our competitors in transportation engineering, planning and design
+include major firms such as Parsons Brinkerhoff, Inc., URS, HNTB and
+Parsons Transportation Group, Inc., as well as many smaller regional
+engineering firms. 
+5 
+Table of Contents 
+In general, the markets
+for the products and services we offer are highly competitive and are
+characterized by rapidly changing technology and evolving standards. Many of
+our current and prospective competitors have longer operating histories,
+greater name recognition, access to larger customer bases and significantly
+greater financial, technical, manufacturing, distribution and marketing
+resources than us. As a result, they may be able to adapt more quickly to new
+or emerging standards or technologies or to devote greater resources to the
+promotion and sale of their products. It is also possible that new competitors
+or alliances among competitors could emerge and rapidly acquire significant
+market share. We believe that our ability to compete effectively in our target
+markets will depend on a number of factors, including the success and timing of
+our new product development, the compatibility of our products with a broad
+range of computing systems, product quality and performance, reliability,
+functionality, price and service and technical support. Our failure to provide
+services and develop and market products that compete successfully with those
+of other suppliers and consultants in our target markets would have a material
+adverse effect on our business, financial condition and results of operations. 
+Intellectual
+Property and Proprietary Rights 
+Our ability to compete
+effectively depends in part on our ability to develop and maintain the
+proprietary aspects of our technology. Our policy is to obtain appropriate
+proprietary rights protection for any potentially significant new technology
+acquired or developed by us. We currently hold ten U.S. patents, which expire
+commencing in 2012, relating to our outdoor image processing techniques used in
+our AutoVue LDW systems. Nine of these patents relate specifically to our LDW
+technology and provide a basis for enhanced functionality for rain sensing and
+improved performance. Our other U.S. patent was issued for an Electronic
+Traffic Monitor related to our Abacus product in the Roadway Sensors segment.
+We also have pending patent applications in Canada and the European Community
+for the Electronic Traffic Monitor. We cannot assure you that any new patents
+will be granted pursuant to these or subsequent applications. 
+In addition to patent
+laws, we rely on copyright and trade secret laws to protect our proprietary
+rights. We attempt to protect our trade secrets and other proprietary
+information through agreements with customers and suppliers, proprietary
+information agreements with our employees and consultants, and other similar
+measures. We do not have any material licenses or trademarks other than those
+relating to product names. We cannot be certain that we will be successful in
+protecting our proprietary rights. While we believe our patents, patent
+applications, software and other proprietary know-how have value, changing
+technology makes our future success dependent principally upon our employees’
+technical competence and creative skills for continuing innovation. 
+Litigation may be
+necessary in the future to enforce our proprietary rights, to determine the
+validity and scope of the proprietary rights of others, or to defend us against
+claims of infringement or invalidity by others. An adverse outcome in such
+litigation or similar proceedings could subject us to significant liabilities
+to third parties, require disputed rights to be licensed from others or require
+us to cease marketing or using certain products, any of which could have a
+material adverse effect on our business, financial condition and results of
+operations. In addition, the cost of addressing any intellectual property
+litigation claim, both in legal fees and expenses, as well as from the
+diversion of management’s resources, regardless of whether the claim is valid,
+could be significant and could have a material adverse effect on our business,
+financial condition and results of operations. 
+Employees 
+We refer to our employees
+as associates. As of May 7, 2010, we employed an aggregate of 221
+associates, including 53 associates in general management, administration and
+finance; 25 associates in sales and marketing; 116 associates in engineering
+and product development; 18 associates in operations, manufacturing and
+quality; and 9 associates in customer service. None of our associates are
+represented by a labor union, and we have never experienced a work stoppage. 
+Government
+Regulation 
+Our manufacturing
+operations are subject to various federal, state and local laws and
+regulations, including those restricting the discharge of materials into the
+environment. We are not involved in any pending or, to our knowledge,
+threatened governmental proceedings, which would require curtailment of our
+operations because of such laws and regulations. We continue to expend funds in
+connection with our compliance with applicable environmental regulations. These
+expenditures have not, however, been significant in the past, and we do not
+expect any significant expenditure in the near future. Currently, compliance
+with foreign laws has not had a material impact on our business and is not
+expected to have a material impact in the near future. 
+ITEM 1A. RISK FACTORS 
+Our
+business is subject to a number of risks, some of which are discussed below.
+Other risks are presented elsewhere in this report and in the information
+incorporated by reference into this report. You should consider the following
+risks carefully in addition to the other information contained in this report
+and our other filings with the SEC, including our subsequent reports on Forms
+10-Q and 8-K, before deciding to buy, sell or hold our common stock. The risks
+and uncertainties described below are not the only ones facing our company.
+Additional risks and uncertainties not presently known to us or that we
+currently deem immaterial may also affect our business operations. If any of
+these risks actually occurs, our business, financial condition, or results of
+operations could be seriously harmed. In that event, the market price for our
+common stock could decline and you may lose all or part of your investment. 
+6 
+Table of Contents 
+The economic slowdown has adversely impacted real estate development,
+reduced and delayed government funding for transportation infrastructure
+projects and initiatives and decreased availability of financial capital for
+our customers, all of which is adversely impacting our net sales and could
+impact our contract revenues. Decreased consumer spending,
+the failure of certain financial institutions and businesses, concerns about
+the availability and cost of credit, and reduced corporate profits and capital
+spending have resulted in a downturn in worldwide economic conditions, as well
+as budgetary shortfalls increasingly present at all levels of government. These
+unfavorable economic conditions are having a negative impact on customer orders
+and government funding of infrastructure projects incorporating our products
+and services. Such factors have and may continue to result in cancellations and
+rescheduling of backlog and customer orders. In addition, the recent decline in
+the U.S. real estate market, particularly in new home and commercial
+construction, has adversely impacted new road construction and is resulting in
+and may continue to result in flat or declining Roadway Sensor and Vehicle
+Sensor net sales in future periods and have also adversely impacted
+Transportation Systems contract revenues. Any of the foregoing economic conditions
+make it extremely difficult for our customers, our suppliers and us to
+accurately forecast and plan future business activities. Additionally, there
+continues to be uncertainties regarding the impact of the federal stimulus
+package and the fact that the accessibility of funds is taking longer than
+originally anticipated, as well as a delay in the passage of a new Federal
+Highway Bill. If such conditions continue or worsen, our business, financial
+condition and results of operations could be materially and adversely affected. 
+Because we depend on government contracts and subcontracts, we face
+additional risks related to contracting with federal, state and local
+governments, including budgetary issues and fixed price contracts. A significant
+portion of our sales are derived from contracts with governmental agencies,
+either as a general contractor, subcontractor or supplier. Government contracts
+represented approximately 45%, 45% and 38% of our total net sales and contract
+revenues for the fiscal years ended March 31, 2010, 2009 and 2008,
+respectively. We anticipate that revenue from government contracts will
+continue to remain a significant portion of our net sales and contract
+revenues. Government business is, in general, subject to special risks and
+challenges, including: 
+· delays in
+funding, including delays in the allocation of funds to state and local
+agencies from the U.S. federal government as a result of the expiration of the
+2005 Federal Highway Bill on October 31, 2009, as well as delays or reductions
+in stimulus funds dedicated for transportation projects; 
+· long purchase
+cycles or approval processes; 
+· competitive
+bidding and qualification requirements; 
+· the impact of
+international conflicts; 
+· performance
+bond requirements; 
+· changes in
+government policies and political agendas; 
+· other
+government budgetary constraints, cut-backs, delays or reallocation of
+government funding; 
+· milestone
+requirements and liquidated damage provisions for failure to meet contract
+milestones; and 
+· international
+conflicts or other military operations that could cause the temporary or
+permanent diversion of government funding from transportation or other
+infrastructure projects. 
+Governmental budgets and
+plans are subject to change without warning. Certain risks of selling to
+governmental entities include dependence on appropriations and administrative
+allocation of funds, changes in governmental procurement legislation and
+regulations and other policies that may reflect political developments or agendas,
+significant changes in contract scheduling, intense competition for government
+business and termination of purchase decisions for the convenience of the
+governmental entity. Substantial delays in purchase decisions by governmental
+entities, and the current constraints on government budgets at the federal,
+state and local level, could cause our net sales and contract revenues and
+income to drop substantially or to fluctuate significantly between fiscal
+periods. 
+7 
+Table of Contents 
+In addition, a large number of our government
+contracts are fixed price contracts. As a result, we may not be able to recover
+any cost overruns we may incur. These fixed price contracts require us to
+estimate the total project cost based on preliminary projections of the project’s
+requirements. The financial viability of any given project depends in large
+part on our ability to estimate these costs accurately and complete the project
+on a timely basis. In the event our costs on these projects exceed the fixed
+contractual amount, we will be required to bear the excess costs. Such
+additional costs would adversely affect our financial condition and results of
+operations. Moreover, certain of our government contracts are subject to
+termination or renegotiation at the convenience of the government, which could
+result in a large decline in our net sales and contract revenues in any given
+period. Our inability to address any of the foregoing concerns or the loss or
+renegotiation of any material government contract could seriously harm our
+business, financial condition and results of operations. 
+California state budgetary constraints may have a material adverse
+impact on us. The state of California has experienced, and is
+continuing to experience, a significant budget shortfall and other related
+budgetary issues and constraints. The state of California has historically been
+and is considered to be a key geographic region for our Roadway Sensors and
+Transportation Systems segments. Ongoing uncertainty as to the timing and
+accessibility of federal stimulus monies to the state, changes in state funding
+allocations to local agencies and municipalities, or other delays in purchasing
+for, or commencement of, transportation projects has and may continue to have a
+negative impact on our net sales and contract revenues and our income. 
+The
+markets in which we operate are highly competitive and have many more
+established competitors, which could adversely affect our sales or the market
+acceptance of our products. We compete with numerous other companies in our target
+markets including, but not limited to, large, multinational corporations, which
+include tier-one automotive suppliers, and many smaller regional engineering
+firms. We believe that as a result of the expected 2013 European mandate for
+LDW and other active safety systems, and an overall awareness of the potential
+benefits of LDW, we will experience an even higher degree of competition from a
+variety of tier-one OEM suppliers and other potential market entrants,
+worldwide. We also expect such competition to increase due to technological
+advancements, industry consolidations and reduced barriers to entry. Increased
+competition is likely to result in loss of market share, price reductions and
+reduced gross margins, any of which could seriously harm our business,
+financial condition and results of operations. For example, a developer of LDW
+systems was acquired by a large multinational organization during our Fiscal
+2009. This new competitor has increased its market share and could be more
+aggressive in both the passenger car and heavy truck markets as a result of its
+greater access to resources and reputation in the market. Furthermore,
+awareness of LDW technology is increasing and other market players have
+developed competing technologies, which may contain improvements or added
+features beyond those offered by our LDW systems. Additionally, from time to
+time, we may be required to re-compete for LDW business from our main customer
+base of heavy truck OEMs. These OEMs could make a supplier change based on
+price, product performance or available features. Should our competition be
+successful, this could adversely affect our ability to successfully market and
+sell our LDW systems to new and existing customers. 
+We compete with existing,
+well-established companies in our Roadway Sensors segment, both domestically
+and abroad. Certain technological barriers to entry make it difficult for new
+competitors to enter the market with competing video or other technologies;
+however, we are aware of new market entrants from time to time. Increased
+competition could result in loss of market share, price reductions and reduced
+gross margins, any of which could seriously harm our business, financial
+condition and results of operations. 
+Many
+of our competitors have far greater name recognition and greater financial,
+technological, marketing, and customer service resources than we do. This may
+allow them to respond more quickly to new or emerging technologies and changes
+in customer requirements. It may also allow them to devote greater resources to
+the development, promotion, sale and support of their products than we can.
+Recent consolidations of end users, distributors and manufacturers in our
+target markets have exacerbated this problem. As a result of the foregoing
+factors, we may not be able to compete effectively in our target markets and
+competitive pressures could adversely affect our business, financial condition
+and results of operations. 
+We may engage in acquisitions of companies or technologies that
+may require us to undertake significant capital infusions and could result
+in disruptions of our business and diversion of resources and management
+attention. We completed the acquisition of certain assets of
+Hamilton Signal in April 2009. We have in the past acquired, and may in
+the future acquire, additional complementary businesses, products, and
+technologies. Acquisitions may require significant capital infusions and, in
+general, acquisitions also involve a number of special risks, including: 
+· potential
+disruption of our ongoing business and the diversion of our resources and
+management’s attention; 
+· the failure to
+retain or integrate key acquired personnel; 
+· the challenge
+of assimilating diverse business cultures, and the difficulties in integrating
+the operations, technologies and information system of the acquired companies; 
+· increased costs
+to improve managerial, operational, financial and administrative systems and to
+eliminate duplicative services; 
+8 
+Table of Contents 
+· the incurrence
+of unforeseen obligations or liabilities; 
+· potential
+impairment of relationships with employees or customers as a result of changes
+in management; and 
+· increased
+interest expense and amortization of acquired intangible assets. 
+Our competitors are also soliciting potential acquisition
+candidates, which could both increase the price of any acquisition targets and
+decrease the number of attractive companies available for acquisition.
+Acquisitions may also materially and adversely affect our operating results due
+to large write-offs, contingent liabilities, substantial depreciation, deferred
+compensation charges or intangible asset amortization, or other adverse tax or
+accounting consequences. We cannot assure you that we will be able to identify
+or consummate any additional acquisitions, successfully integrate any
+acquisitions or realize the benefits anticipated from any acquisition. 
+We may be unable to attract and retain key personnel, which could
+seriously harm our business. Due to the specialized
+nature of our business, we are highly dependent on the continued service of our
+executive officers and other key management, engineering and technical
+personnel. The loss of any of our officers, or any of our other executives or
+key members of management could adversely affect our business, financial
+condition, or results of operations. Our success will also depend in large part
+upon our ability to continue to attract, retain and motivate qualified
+engineering and other highly skilled technical personnel. In particular, the
+future success of our Transportation Systems segment will depend on our ability
+to hire additional qualified engineers and planners. Competition for qualified
+employees, particularly development engineers, is intense. We may not be able
+to continue to attract and retain sufficient numbers of such highly skilled
+employees. Our inability to attract and retain additional key employees or the
+loss of one or more of our current key employees could adversely affect our
+business, financial condition and results of operations. 
+Our profitability could be
+adversely affected if we are not able to maintain adequate utilization of our
+Transportation Systems workforce. The cost of providing our
+Transportation Systems engineering and consulting services, including the
+extent to which we utilize our workforce, affects our profitability. The rate
+at which we utilize our workforce is affected by a number of factors,
+including: 
+· our ability to
+transition employees from completed projects to new assignments and to hire and
+assimilate new employees; 
+· our ability to
+forecast demand for our services and thereby maintain an appropriate headcount
+in our various regions; 
+· our need to
+devote time and resources to training, business development, professional
+development and other non-chargeable activities; and 
+· our ability to
+match the skill sets of our employees to the needs of the marketplace. 
+Our use of the percentage of completion method of accounting for our
+contract revenues could result in a reduction or reversal of previously recorded
+revenues and profits. A significant portion of our total net sales
+and contract revenues are measured and recognized using the percentage of
+completion method of accounting. Our use of this accounting method results in
+recognition of revenues and profits ratably over the life of a contract, based
+generally on the proportion of costs incurred to date to total costs expected
+to be incurred for the entire project. The effects of revisions to
+revenues and estimated costs are recorded when the amounts are known or can be
+reasonably estimated. Such revisions could occur in any period and their
+effects could be material. Although we have historically made reasonably
+reliable estimates of the progress towards completion of long-term engineering,
+program management, construction management or construction contracts, the
+uncertainties inherent in the estimating process make it possible for actual
+costs to vary materially from estimates, including reductions or reversals of
+previously recorded revenues and profits. 
+Our failure to successfully bid on new contracts and renew existing
+contracts could reduce our revenues and profits. Our business
+depends on our ability to successfully bid on new contracts and renew existing
+contracts with private and public sector customers. Contract proposals and
+negotiations are complex and frequently involve a lengthy bidding and selection
+process, which are affected by a number of factors, such as market conditions,
+financing arrangements and required governmental approvals. For example, a
+customer may require us to provide a surety bond or letter of credit to protect
+the client should we fail to perform under the terms of the contract. If
+negative market conditions arise, or if we fail to secure adequate financial
+arrangements or the required governmental approval, we may not be able to
+pursue particular projects, which could adversely reduce or eliminate our
+profitability. 
+9 
+Table of Contents 
+We may experience
+production gaps that could materially and adversely impact our sales and
+financial results and the ultimate acceptance of our products. It is possible
+that we could experience unforeseen quality control issues or part shortages as
+we adjust production to meet current demand for our products. We have
+historically used single suppliers for certain significant components in our
+products. Should any such delay or disruption occur, or should a key supplier
+discontinue operations because of the current economic climate, our future
+sales will likely be materially and adversely affected. Additionally, we rely
+heavily on select contract manufacturers to produce many of our products and do
+not have any long-term contracts to guarantee supply of such products. Although
+we believe our contract manufacturers have sufficient capacity to meet our
+production schedules for the foreseeable future and we believe we could find
+alternative contract manufacturing sources for many of our products, if
+necessary, we could experience a production gap if for any reason our contract
+manufacturers were unable to meet our production requirements and our cost of
+goods sold could increase, adversely affecting our margins. 
+If we are unable to develop and introduce new products and product
+enhancements successfully and in a cost-effective and timely manner, or are
+unable to achieve market acceptance of our new products, our operating results
+would be adversely affected. We believe our revenue growth
+and future operating results will depend on our ability to complete development
+of new products and enhancements, introduce these products in a timely,
+cost-effective manner, achieve broad market acceptance of these products and
+enhancements, and reduce our production costs. We cannot guarantee the success
+of these products, and we may not be able to introduce any new products or any
+enhancements to our existing products on a timely basis, or at all. In
+addition, the introduction of any new products could adversely affect the sales
+of certain of our existing products. 
+We believe that we must continue to make substantial
+investments to support ongoing research and development in order to remain
+competitive. We need to continue to develop and introduce new products that
+incorporate the latest technological advancements in outdoor image processing
+hardware, software and camera technologies in response to evolving customer
+requirements. We cannot assure you that we will be able to adequately manage
+product transition issues. Our business and results of operations could be
+adversely affected if we do not anticipate or respond adequately to
+technological developments or changing customer requirements or if we cannot
+adequately manage inventory issues typically related to new product transitions
+and introductions. We cannot assure you that any such investments in research
+and development will lead to any corresponding increase in revenue. 
+Market acceptance of our new products depends upon
+many factors, including our ability to accurately predict market requirements
+and evolving industry standards, our ability to resolve technical challenges in
+a timely and cost-effective manner, our ability to qualify any new products
+with OEMs and achieve manufacturing efficiencies, the perceived advantages of
+our new products over traditional products and the marketing capabilities of
+our independent distributors and strategic partners, including Valeo’s ability
+to expand sales of LDW systems in the passenger car market. The success of our
+LDW system will also depend in part on the success of the automotive vehicles
+that incorporate our technology, as well as the success of optional equipment
+that OEMs bundle with our technologies. 
+Certain of the components used in our products may
+need to be re-engineered in the next 12 to 36 months as the industry is moving
+towards a standard of using lead-free components. We cannot assure you as to
+our ability to successfully redesign our products to incorporate compliant
+components and gain market acceptance of such redesigned products. In addition,
+we may experience a shortage of products as a result of potential scarcity of
+lead-free components. 
+Our business and results of operations could also be
+seriously harmed by any significant delays in our new product development.
+Certain of our new products could contain undetected design faults and software
+errors or “bugs” when first released by us, despite our testing. We may not
+discover these faults or errors until after a product has been installed and
+used by our customers. Any faults or errors in our existing products or in any
+new products may cause delays in product introduction and shipments, require
+design modifications or harm customer relationships, any of which could
+adversely affect our business and competitive position. 
+New environmental regulations may result in a decline in
+our Vehicle Sensors net sales. From
+time to time, environmental regulations are enacted, which can significantly
+increase the cost of manufacturing new vehicles as well as the cost of
+maintaining existing vehicles and truck fleets. As a result, we could
+experience a decline in sales of our Vehicle Sensors products as truck and
+vehicle manufacturers and fleet operators attempt to control their costs. 
+We depend upon Valeo to market our LDW technologies for the OEM
+passenger car market. We have granted Valeo the exclusive right to
+sell and manufacture our LDW system to the worldwide passenger car market in
+exchange for royalty payments for each LDW unit sold. As such, the future
+success and broad market acceptance of our technologies in the passenger car
+market will depend upon Valeo’s ability to manufacture, market and sell our
+technologies, and to convince more OEM passenger car manufacturers to adopt our
+technologies. To date, we have not generated significant royalties from Valeo’s
+efforts and have only been designed into one car OEM product line. If Valeo
+does not devote considerable resources and aggressively pursue opportunities,
+our expansion into the passenger car market, and our related revenues from
+contract engineering services and royalty revenues, could be adversely affected
+or not materialize as originally anticipated. 
+10 
+Table of Contents 
+If we do not keep pace with rapid technological changes and evolving
+industry standards, we will not be able to remain competitive and there will be
+no demand for our products. Our markets are in general
+characterized by the following factors: 
+· rapid
+technological advances; 
+· downward price
+pressure in the marketplace as technologies mature; 
+· changes in
+customer requirements; 
+· additional
+qualification requirements related to new products or components; 
+· frequent new
+product introductions and enhancements; 
+· inventory
+issues related to transition to new or enhanced models; and 
+· evolving
+industry standards and changes in the regulatory environment. 
+Our future success will depend upon our ability to
+anticipate and adapt to changes in technology and industry standards, and to
+effectively develop, introduce, market and gain broad acceptance of new
+products and product enhancements incorporating the latest technological
+advancements. In particular, our LDW systems are incorporated into automobiles
+and trucks that face significant technological changes in each model year and
+among different vehicle models. Accordingly, we must adapt our technology from
+time to time to function with such changes. 
+Our international business operations may be threatened by many
+factors that are outside of our control. While we historically have
+had limited international sales and operations experience, we began work on our
+first overseas contracts in Abu Dhabi and Dubai in Fiscal 2010. We plan to
+expand our international efforts in the future with respect to all three of our
+segments, but cannot assure you that we will be successful in those efforts.
+International operations subject us to various inherent risks including, among
+others: 
+· currency
+fluctuations and restrictions; 
+· political,
+social and economic instability, as well as international conflicts and acts of
+terrorism; 
+· longer accounts
+receivable payment cycles; 
+· import and
+export license requirements and restrictions of the United States and each
+other country in which we operate; 
+· unexpected
+changes in regulatory requirements, tariffs and other trade barriers or
+restrictions; 
+· the burdens of
+compliance with a wide variety of foreign laws and more restrictive labor laws
+and obligations; 
+· difficulties in
+managing and staffing international operations; 
+· potentially
+adverse tax consequences; and 
+· reduced
+protection for intellectual property rights in some countries. 
+Substantially all of our international sales are
+denominated in U.S. dollars. As a result, an increase in the relative value of
+the dollar could make our products more expensive and potentially less price
+competitive in international markets. We do not currently engage in any transactions
+as a hedge against risks of loss due to foreign currency fluctuations. 
+Any of the factors mentioned above may adversely
+affect our future international sales and, consequently, affect our business,
+financial condition and operating results. Additionally, as we pursue the
+expansion of our international business, certain fixed and other overhead costs
+could outpace our revenues, thus adversely affecting our results of operations.
+We may likewise face local competitors in certain international markets who are
+more established, have greater economies of scale and stronger customer
+relationships. Furthermore, as we increase our international sales, our total
+revenues may also be affected to a greater extent by seasonal fluctuations
+resulting from lower sales that typically occur during the summer months in
+Europe and other parts of the world. 
+If our
+internal controls over financial reporting do not comply with the requirements
+of the Sarbanes-Oxley Act, our business and stock price could be adversely affected.
+Section 404 of the Sarbanes-Oxley Act of 2002 currently requires
+us to evaluate the effectiveness of our internal controls over financial
+reporting at the end of each fiscal year and to include a management report
+assessing the effectiveness of our internal controls over financial reporting
+in all annual reports. Currently, we expect that 
+11 
+Table of Contents 
+beginning in our fiscal year
+ending March 31, 2011, our independent registered public accounting firm
+will also be required to attest to, and report on, the effectiveness of our
+internal controls over financial reporting. We may not be able to complete the
+work required for such attestation on a timely basis, and even if we timely
+complete such requirements, our independent registered public accounting firm
+may still conclude that our internal controls over financial reporting are not
+effective. 
+Our management, including our CEO and CFO, does not
+expect that our internal controls over financial reporting will prevent all
+errors and all fraud. A control system, no matter how well designed and
+operated, can provide only reasonable, not absolute, assurance that the control
+system’s objectives will be met. Further, the design of a control system must
+reflect the fact that there are resource constraints, and the benefits of
+controls must be considered relative to their costs. Because of the inherent
+limitations in all control systems, no evaluation of controls can provide
+absolute assurance that all control issues and instances of fraud, if any,
+within Iteris have been or will be detected. These inherent limitations include
+the realities that judgments in decision-making can be faulty and that
+breakdowns can occur because of simple errors or mistakes. Controls can also be
+circumvented by the individual acts of some persons, by collusion of two or
+more people, or by management override of the controls. The design of any
+system of controls is based in part on certain assumptions about the likelihood
+of future events, and we cannot assure you that any design will succeed in
+achieving its stated goals under all potential future conditions. Over time,
+our controls may become inadequate because of changes in conditions or
+deterioration in the degree of compliance with policies or procedures. Because
+of the inherent limitations in a cost-effective control system, misstatements
+due to error or fraud may occur and not be detected. 
+Our quarterly operating results fluctuate as a result of many factors.
+Therefore, we may fail to meet or exceed the expectations of securities
+analysts and investors, which could cause our stock price to decline. Our quarterly
+revenues and operating results have fluctuated and are likely to continue to
+vary from quarter to quarter due to a number of factors, many of which are not
+within our control. Factors that could affect our revenues include, among
+others, the following: 
+· delays in
+government contracts and funding from time to time and budgetary constraints at
+the federal, state and local levels; 
+· our ability to
+access stimulus funding, funding from a new Federal Highway Bill or other
+funding; 
+· declines in new
+home and commercial real estate construction and related road and other
+infrastructure construction; 
+· changes in our pricing
+policies and the pricing policies of our suppliers and competitors, pricing
+concessions on volume sales, as well as increased price competition in general; 
+· the long lead times
+associated with government contracts or required by vehicle manufacturers; 
+· the size, timing,
+rescheduling or cancellation of significant customer orders; 
+· our ability to control
+costs; 
+· our ability to raise
+additional capital; 
+· the mix of our products and
+services sold in a quarter, which mix has varied and is expected to continue to
+vary from time to time; 
+· seasonality due to winter
+weather conditions; 
+· our ability to develop,
+introduce, patent, market and gain market acceptance of new products,
+applications and product enhancements in a timely manner, or at all; 
+· market acceptance of the
+products incorporating our technologies and products; 
+· the introduction of new
+products by competitors; 
+· the availability and cost of
+components used in the manufacture of our products; 
+· our success in expanding and
+implementing our sales and marketing programs; 
+· the effects of technological
+changes in our target markets; 
+· the amount of our backlog at
+any given time; 
+· the nature of our government
+contracts; 
+12 
+Table of
+Contents 
+· deferrals of customer orders
+in anticipation of new products, applications or product enhancements; 
+· risks and uncertainties
+associated with our international business; 
+· currency fluctuations and
+our ability to get currency out of certain foreign countries; and 
+· general economic and
+political conditions; and 
+· international conflicts and
+acts of terrorism. 
+Due to all of the factors listed above as well as
+other unforeseen factors, our future operating results could be below the
+expectations of securities analysts or investors. If that happens, the trading
+price of our common stock could decline. As a result of these quarterly
+variations, you should not rely on quarter-to-quarter comparisons of our
+operating results as an indication of our future performance. 
+We
+have experienced a decline in our net sales and contract revenues over the last
+fiscal year. If we fail to manage this decline effectively, we may be
+unable to execute our business plan and may experience future weaknesses
+in our operating results. We have expanded our overall business in the past few
+years; however, we experienced a reduction in our net sales and contract
+revenues in Fiscal 2010. Based on our business objectives, and in order to
+achieve future growth, we will need to continue to add additional qualified
+personnel, and invest in additional research and development and sales and
+marketing activities. Our past expansion has placed, and future expansion is
+expected to place, a significant strain on our managerial, administrative,
+operational, financial and other resources. If we are unable to manage these
+activities successfully, our growth, our business, our financial condition and
+our results of operations could continue to be adversely affected. 
+We may not be able to adequately protect or enforce our
+intellectual property rights, which could harm our competitive position. If we are not
+able to adequately protect or enforce the proprietary aspects of our
+technology, competitors could be able to access our proprietary technology and
+our business, financial condition and results of operations will likely be
+seriously harmed. We currently attempt to protect our technology through a
+combination of patent, copyright, trademark and trade secret laws, employee and
+third party nondisclosure agreements and similar means. Despite our efforts,
+other parties may attempt to disclose, obtain or use our technologies or
+systems. Our competitors may also be able to independently develop products
+that are substantially equivalent or superior to our products or design around
+our patents. In addition, the laws of some foreign countries do not protect our
+proprietary rights as fully as do the laws of the United States. As a result,
+we may not be able to protect our proprietary rights adequately in the United
+States or abroad. 
+Litigation
+may be necessary in the future to enforce our intellectual property rights or
+to determine the validity and scope of the proprietary rights of others.
+Litigation may also be necessary to defend against claims of infringement or
+invalidity by others. An adverse outcome in litigation or any similar
+proceedings could subject us to significant liabilities to third parties,
+require us to license disputed rights from others or require us to cease
+marketing or using certain products or technologies. We may not be able to
+obtain any licenses on terms acceptable to us, or at all. We also may have to
+indemnify certain customers or strategic partners if it is determined that we
+have infringed upon or misappropriated another party’s intellectual property.
+Any of these results could adversely affect our business, financial condition
+and results of operations. In addition, the cost of addressing any intellectual
+property litigation claim, including legal fees and expenses, and the diversion
+of management’s attention and resources, regardless of whether the claim is
+valid, could be significant and could seriously harm our business, financial
+condition and results of operations. 
+We may need to raise additional capital in the future, which
+may not be available on terms acceptable to us, or at all. Until recently, we have
+historically generated significant net losses and operating losses, and have
+experienced volatility in our cash flows from operations from year to year.
+Although we entered into a $19.5 million credit facility, effective October 2008,
+should we have an event of default, which includes, among other things, a
+failure to meet certain financial covenants and a material adverse change in
+the business, the bank could choose to limit or take away our ability to borrow
+these or any funds. Should this occur, or if the credit markets further
+tighten, we may need or choose to raise additional capital to pursue
+acquisitions or to expand our operations. 
+At March 31,
+2010, we had $10.4 million of cash and cash equivalents and the availability of
+borrowing against our $12.0 million line of credit to fund our operations,
+subject to certain funded to debt to EBITDA requirements. We may need to raise
+additional capital in the near future to fund our operations or to repay
+indebtedness. Such additional capital may be raised through bank borrowings, or
+other debt or equity financings. We cannot assure you that any additional
+capital will be available on a timely basis, on acceptable terms, or at all,
+and such additional financing may result in further dilution to our
+stockholders. 
+13 
+Table of Contents 
+Our capital requirements will depend on many
+factors, including, but not limited to: 
+· market
+acceptance of our products and product enhancements, and the overall level of
+sales of our products; 
+· our ability to
+control costs; 
+· the supply of
+key components for our products; 
+· our ability to
+increase revenue and net income; 
+· increased
+research and development expenses and sales and marketing expenses; 
+· our need to
+respond to technological advancements and our competitors’ introductions of new
+products or technologies; 
+· capital
+improvements to new and existing facilities and enhancements to our
+infrastructure and systems; 
+· potential
+acquisitions of businesses and product lines; 
+· our
+relationships with customers and suppliers; 
+· government
+budgets, political agendas and other funding issues, including potential delays
+in government contract awards; 
+· our ability to
+successfully negotiate credit arrangements with our bank and the state of the
+financial markets, in general; and 
+· general
+economic conditions, including the effects of the current economic slowdown and
+international conflicts. 
+If our capital requirements are materially different
+from those currently planned, we may need additional capital sooner than
+anticipated. If additional funds are raised through the issuance of equity or
+convertible debt securities, the percentage ownership of our stockholders will
+be reduced and such securities may have rights, preferences and privileges
+senior to our common stock. Additional equity or debt financing may not be
+available on favorable terms, on a timely basis, or at all. If adequate funds
+are not available or are not available on acceptable terms, we may be unable to
+continue our operations as planned, develop or enhance our products, expand our
+sales and marketing programs, take advantage of future opportunities or respond
+to competitive pressures. 
+Prior
+to the fiscal year ended March 31, 2006, we historically generated
+significant losses and may experience losses in the future. We cannot
+assure you that we will be able to sustain or improve our financial
+performance, or that we will be able to continue to achieve profitability on a
+quarterly or annual basis in the future. Our ability to maintain profitability
+in future periods could be impacted by budgetary constraints, government and
+political agendas, economic instability and other items that are not in our control.
+Most of our expenses are fixed in advance. As such, we generally are unable to
+reduce our expenses significantly in the short-term to compensate for any
+unexpected delay or decrease in anticipated revenues. As a result, we may
+experience operating losses and net losses in the future, which would make it
+difficult to fund our operations and achieve our business plan, and could cause
+the market price of our common stock to decline. 
+The trading price of our common stock is highly volatile. The trading
+price of our common stock has been subject to wide fluctuations in the past.
+Since January 2001, our Class A common stock (now known as our common
+stock) has traded at prices as low as $0.45 per share and as high as $8.00 per
+share. The market price of our common stock could continue to fluctuate in the
+future in response to various factors, including, but not limited to: 
+· quarterly variations in
+operating results; 
+· our ability to control
+costs, improve cash flow and sustain profitability; 
+· our ability to raise
+additional capital; 
+· shortages announced by
+suppliers; 
+· announcements of
+technological innovations or new products or applications by our competitors,
+customers or us; 
+· transitions to new products
+or product enhancements; 
+· acquisitions of businesses,
+products or technologies; 
+· the impact of any
+litigation; 
+14 
+Table of
+Contents 
+· changes in investor
+perceptions; 
+· government funding,
+political agendas and other budgetary constraints; 
+· changes in earnings
+estimates or investment recommendations by securities analysts; and 
+· international conflicts,
+political unrest and acts of terrorism. 
+The stock market in general has from time to time
+experienced volatility, which has often affected the market prices of equity
+securities of many technology companies. This volatility has often been
+unrelated to the operating performance of these companies. These broad market fluctuations
+may adversely affect the market price of our common stock. In the past,
+companies that have experienced volatility in the market price of their
+securities have been the subject of securities class action litigation. If we
+were to become the subject of a class action lawsuit, it could result in
+substantial losses and divert management’s attention and resources from other
+matters. 
+We could experience negative financial impacts arising from
+developments in contingencies created under our previous structure or by former
+subsidiaries. Although we divested ourselves of all business units
+prior to October 2004, from time to time we could experience unforeseen
+developments in contingencies related to our former subsidiaries. Although we
+are not aware of any other material contingencies, it is possible other matters
+could be brought against us in connection with activities related to former
+subsidiaries and that such matters could materially and adversely affect our
+financial results and cash flows. 
+Certain provisions of our
+charter documents may discourage a third party from acquiring us and
+may adversely affect the price of our common stock. Certain
+provisions of our certificate of incorporation could make it difficult for a
+third party to acquire us, even though an acquisition might be beneficial to
+our stockholders. Such provisions could limit the price that investors might be
+willing to pay in the future for shares of our common stock. Under the terms of
+our certificate of incorporation, our Board of Directors is authorized to
+issue, without stockholder approval, up to 2,000,000 shares of preferred stock
+with voting, conversion and other rights and preferences superior to those of
+our common stock. In addition, in August 2009, we adopted a stockholder rights
+plan and declared a dividend of preferred stock purchase rights to our
+stockholders. Generally, the stockholder rights plan provides that if a person
+or group acquires 15% or more of our common stock, subject to certain
+exceptions and under certain circumstances, the rights may be exchanged by us
+for common stock or the holders of the rights, other than the acquiring person
+or group, could acquire additional shares of our capital stock at a discount
+off of the then current market price. Such exchanges or exercise of rights
+could cause substantial dilution to a particular acquirer and discourage the
+acquirer from pursuing our company. The mere existence of a stockholder rights
+plan often delays or makes a merger, tender offer or proxy contest more
+difficult. 
+ITEM 1B. UNRESOLVED STAFF COMMENTS 
+None. 
+ITEM 2. PROPERTIES 
+Our headquarters and
+principal operations are housed in approximately 52,000 square feet of leased
+space located at 1700 Carnegie Avenue, Santa Ana, California. This facility
+lease expires in 2015 and contains an option to extend the lease for an
+additional five years at the market rate at that time. 
+For additional
+information regarding our obligations under property leases, see Note 6 of
+Notes to Consolidated Financial Statements, included in Part IV, Item 15
+of this report. 
+ITEM 3. LEGAL PROCEEDINGS 
+The information set forth
+under the heading “Litigation” under Note 6 of Notes to Consolidated Financial
+Statements, included in Part IV, Item 15 of this report, is incorporated
+herein by reference. 
+ITEM 4. (REMOVED AND RESERVED) 
+15 
+Table of
+Contents 
+PART II 
+ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED
+STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+Market Information and Holders 
+Our common stock is
+traded on the NYSE Amex under the symbol “ITI.” 
+The following table sets forth, for the periods indicated, the high and
+low sales prices for our common stock as reported by NYSE Amex: 
+High 
+Low 
+Fiscal 2010 
+Quarter Ended June 30, 2009 
+$ 
+1.45 
+$ 
+1.14 
+Quarter Ended September 30, 2009 
+1.73 
+1.15 
+Quarter Ended December 31, 2009 
+1.60 
+1.37 
+Quarter Ended March 31, 2010 
+2.04 
+1.31 
+Fiscal 2009 
+Quarter Ended June 30, 2008 
+$ 
+2.98 
+$ 
+2.14 
+Quarter Ended September 30, 2008 
+2.45 
+1.65 
+Quarter Ended December 31, 2008 
+1.83 
+1.16 
+Quarter Ended March 31, 2009 
+1.50 
+0.98 
+On May 14, 2010, the
+last reported sales price of our common stock on the NYSE Amex was $1.77. As of May 14, 2010, we had
+407 holders of record of our common stock according to information
+furnished by our transfer agent. 
+Dividend Policy 
+We have never paid or
+declared cash dividends on our common stock, and have no current plans to pay
+such dividends in the foreseeable future. We currently intend to retain any
+earnings for working capital and general corporate purposes. The payment of any
+future dividends will be at the discretion of our Board of Directors and will
+depend upon a number of factors, including, but not limited to, future earnings,
+the success of our business, our capital requirements, our general financial
+condition and future prospects, general business conditions, the consent of our
+lender and such other factors as the Board of Directors may deem relevant. 
+ITEM 6. SELECTED FINANCIAL DATA 
+As a smaller reporting
+company, we are not required to make any disclosure pursuant to this Item 6. 
+ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
+OF OPERATIONS 
+You should read the following
+discussion and analysis in conjunction with our Consolidated Financial
+Statements and related Notes thereto included in Part IV, Item 15 of this
+report and the “Risk Factors” section in Item 1A, as well as other
+cautionary statements and risks described elsewhere in this report, before
+deciding to purchase, hold or sell our common stock. 
+Overview 
+General. We are a leader in the traffic management
+market focused on the development and application of advanced technologies that
+reduce traffic congestion and improve the safety of surface transportation
+systems infrastructure. Additionally, we believe our products and services, as
+well as sound traffic management, minimize the environmental impact of traffic
+congestion. By combining outdoor image processing, traffic engineering and
+information technology, we offer a broad range of ITS and driver safety
+solutions to customers in the U.S. and internationally. 
+Business
+Segments. We currently operate in three reportable segments:
+Roadway Sensors, Vehicle Sensors and Transportation Systems. The Roadway
+Sensors segment includes our Vantage, VersiCam and Pico vehicle detection
+systems for traffic intersection control, incident detection and certain
+highway traffic data collection applications. The Vehicle Sensors segment
+includes our LDW products and is comprised of all of our activities related to
+in-vehicle safety. The Transportation Systems segment includes transportation
+engineering and consulting services, and the development of transportation
+management and traveler information systems for the ITS industry. 
+16 
+Table of Contents 
+Our Roadway Sensors
+segment product line uses advanced image processing technology to capture and
+analyze video images through sophisticated algorithms, enabling vehicle
+detection and transmission of both video images and data using various
+communication technologies. 
+· Our Vantage video detection systems detect vehicle presence, count,
+speed and other traffic data used in traffic management systems. Our Vantage
+systems give traffic managers the ability to mitigate roadway congestion by
+modifying traffic signal timing or detecting incidents quickly. 
+· VersiCam, our integrated camera and processor video detection system,
+is a cost-efficient video detection system for smaller intersections that
+require only a few detection points. 
+· Pico, our compact video detection system introduced in December 2009,
+was developed primarily to address international video detection needs, and was
+designed for easy installation and configuration. 
+We anticipate that future
+growth domestically and internationally, particularly in developing countries,
+will be dependent in part on the continued adoption of above-ground video
+detection technologies, instead of traditional in-pavement loop technology, to
+manage traffic. 
+Our Vehicle Sensors
+segment addresses the leading cause of roadway fatalities: lane change, roadway
+departure and rear-end collision accidents. We developed the world’s first
+production LDW system and offer a proven system that is available as an OEM and
+aftermarket option on heavy trucks worldwide and as an option in certain passenger
+cars. Our LDW products utilize video detection images to detect when a vehicle
+begins to drift toward an unintended lane change. When this occurs, the unit
+automatically emits a distinctive rumble strip or other audible warning sound,
+alerting the driver to make a correction. We believe that as a result of the
+expected 2013 EU mandate for LDW and other active safety systems, and an
+overall awareness of the potential benefits of LDW, that we will experience an
+even higher degree of competition from a variety of tier-one OEM suppliers and
+other potential market entrants, worldwide. While we believe that this
+increased competition validates the long-term market opportunity for LDW
+systems in commercial vehicles, it could also adversely effect our future LDW
+sales and margins. We are currently working with our European OEM customer base
+to establish long-term supply agreements that extend to 2013 and beyond in
+order to meet the anticipated increase in demand; however, we cannot assure you
+that our efforts will be successful or that the increase in demand will occur.
+We have entered into an exclusive license of our LDW technology to our
+strategic partner, Valeo, for the passenger car market. Additionally, we and
+our partner have experienced a greater degree of competition in the passenger
+car market. Several passenger car OEMs have recently introduced vehicle
+platforms with competing LDW systems. However, Valeo continues to pursue
+opportunities in the passenger car market. 
+In addition to our LDW
+systems, our Vehicle Sensors portfolio includes radar-based Forward Collision
+Warning and Blind Spot Warning systems for the North American truck market,
+which were both introduced in August 2008, and our SafetyDirect product, a
+system that reports driver performance data captured by our LDW system, and has
+the ability to relay this data directly to fleet operators through integration
+with the truck’s existing fleet communications system. We offer the FCW and BSW
+features through the resale of Delphi’s radar-based systems, for which we are
+the exclusive North American dealer, while SafetyDirect was internally
+developed. These products, together with our LDW products, combine to create a
+suite of active safety driver assistance features focused on reducing the
+number of motor vehicle crashes and the severity of crash-related injuries. 
+Our
+Transportation Systems segment includes transportation engineering and
+consulting services focused on the planning, design, development and
+implementation of software-based systems that integrate sensors, video
+surveillance, computers, and advanced communications equipment to enable public
+agencies to monitor, control and direct traffic flow, assist in the quick
+dispatch of emergency crews and distribute real-time information about traffic
+conditions. Our services include planning, design and implementation of surface
+transportation infrastructure systems. We perform analysis and study goods
+movement, commercial vehicle operations, travel demand forecasting and systems
+engineering, and identify mitigation measures to reduce traffic congestion.
+Historically, these services and systems have primarily been sold to local,
+state and national transportation agencies in the United States under a broad
+range of fixed price and cost plus fixed fee contracts; however, in the current
+fiscal year, we began work on our first two overseas contract awards in Abu
+Dhabi and Dubai. We plan to continue to pursue additional international
+opportunities for our Transportation Systems segment. 
+Our Transportation Systems segment is largely
+dependent upon governmental funding and is affected by state and local
+budgetary issues. We believe the overall expansion of our Transportation
+Systems segment in recent years past was due in part to the passage of the
+Federal Highway Bill in 2005, combined with increased transportation funds
+available at state and local agencies throughout the country. The 2005 Federal
+Highway Bill expired on October 31, 2009, and Congress is currently in
+negotiations regarding future extensions. We anticipate delays in the
+enactment of a new Federal Highway Bill, and until such time as a bill becomes
+law, the allotment of transportation funds in federal, state and local budgets
+may be uncertain and we believe that prolonged uncertainty may adversely impact
+our net sales and contract revenues and our overall financial performance in
+future periods. 
+17 
+Table of Contents 
+Business Trends. Looking forward, we remain cautious about
+our business, given the continued uncertain global economic conditions and the
+challenging financial markets. This unfavorable environment has, and may
+continue to, negatively affect demand for our products and services for the
+foreseeable future. Likewise, our ability to accurately forecast business
+trends may be impaired. 
+Despite the federal stimulus package that was passed
+in 2009, many municipalities and other state and local agencies continue to face
+budgetary issues. As a result, spending for new roadways, new systems to
+address traffic congestion and other transportation infrastructure improvements
+has been delayed or eliminated in some cases. We believe that the need to
+rebuild and modernize aging transportation infrastructure will continue, and in
+addition to funds available through the stimulus package and federal highway
+bills, there exist a variety of other funding mechanisms that support
+transportation infrastructure and related projects, including bonds, dedicated
+sales and gas tax measures and other alternative funding sources. However, we
+currently cannot determine when or if such funding sources will be
+available or the extent to which we may benefit from future sources of
+funding for transportation-related projects. 
+During
+Fiscal 2010, we introduced certain new products including Abacus and Pico. We
+also completed the acquisition of certain assets of Hamilton Signal, which
+included the Abacus system, for an aggregate cash purchase price of
+approximately $518,000. This acquisition has afforded us with the opportunity
+to provide our customers with traffic and incident detection data from our
+installed base of surveillance cameras. 
+Critical
+Accounting Policies and Estimates 
+Management’s
+Discussion and Analysis of Financial Condition and Results of Operations is
+based on our consolidated financial statements included herein, which have been
+prepared in accordance with accounting principles generally accepted in the
+United States. The preparation of these financial statements requires
+management to make estimates and assumptions that affect the reported amounts
+of assets and liabilities and related disclosures of contingent assets and
+liabilities at the date of the financial statements and the reported amounts of
+revenues and expenses during the reporting period. On an ongoing basis, we
+evaluate these estimates and assumptions, including those related to the
+collectibility of accounts receivable, the valuation of inventories, the
+recoverability of long-lived assets and goodwill, the realizability of deferred
+tax assets, accounting for stock-based compensation, the valuation of equity
+instruments, warranty reserves and other contingencies. We base these estimates
+on historical experience and on various other factors that we believe to be
+reasonable under the circumstances, the results of which form the basis for
+making judgments about the carrying values of assets and liabilities that are
+not readily apparent from other sources. These estimates and assumptions by
+their nature involve risks and uncertainties, and may prove to be inaccurate.
+In the event that any of our estimates or assumptions are inaccurate in any
+material respect, it could have a material adverse effect on our reported
+amounts of assets and liabilities at the date of the financial statements and
+the reported amounts of revenues and expenses during the reporting period. 
+The
+following critical accounting policies affect our more significant judgments
+and estimates used in the preparation of our consolidated financial statements. 
+Revenue
+Recognition. We record product revenues and related costs of
+sales upon transfer of title, which is generally upon shipment or, if required,
+upon acceptance by the customer, provided that we believe collectibility of the
+net sales amount is reasonably assured. Accordingly, at the date revenue is
+recognized, the significant uncertainties concerning the sale have been
+resolved. 
+Contract revenues are derived primarily from
+long-term contracts with governmental agencies. Contract revenues include costs
+incurred plus a portion of estimated fees or profits determined using the
+percentage of completion method of accounting based on the relationship of
+costs incurred to total estimated costs. Any anticipated losses on contracts
+are charged to earnings when identified. Changes in job performance and
+estimated profitability, including those arising from contract penalty
+provisions and final contract settlements, may result in revisions to
+recognized costs and revenues and are recognized in the period in which the
+revisions are determined. Profit incentives are included in revenue when their
+realization is reasonably assured. Under the percentage of completion method,
+recognition of profit is dependent upon the accuracy of a variety of estimates,
+including engineering progress, materials quantities, and achievement of
+milestones, incentives, penalty provisions, labor productivity, cost estimates
+and others. Such estimates are based on various professional judgments we
+make with respect to those factors and are subject to change as the project
+proceeds and new information becomes available. 
+In addition to product
+and contract revenues, we derive revenue from the provision of specific
+non-recurring contract engineering services to our strategic partner, Valeo,
+related to our LDW systems, and royalties earned on unit sales of our LDW
+systems by Valeo to the passenger car market. Non-recurring contract
+engineering revenues are recognized in the period in which the related services
+are performed. Royalty revenues are recorded based on unit sales of our
+products by Valeo and are recognized in the period in which such sales occur.
+Non-recurring contract engineering revenues and royalty revenues are included
+in our net sales. 
+18 
+Table of Contents 
+Revenues
+from follow-on service and support, for which we generally charge separately,
+are recorded in the period in which the services are performed and are included
+in our net sales. 
+Accounts
+Receivable. We estimate the collectibility of customer
+receivables on an ongoing basis by reviewing invoices outstanding greater than
+a certain period of time. We record an allowance for doubtful accounts for
+specific receivables deemed to be at risk for collection as well as a general
+allowance based on our historical collections experience. Considerable judgment
+is required in assessing and estimating the ultimate realization of trade
+receivables, including the current credit-worthiness of each customer. If the
+financial condition of our customers deteriorates, resulting in an impairment
+of their ability to make required payments, additional allowances may be
+required that could adversely affect our operating results. 
+Inventories. Inventories
+consist of finished goods, work-in-process and raw materials and are stated at
+the lower of cost or market. We write down the carrying value of our
+inventories to net realizable value for estimated excess and obsolete
+inventories in an amount equal to the difference between the cost of the
+inventories and their estimated realizable value. These estimates are based on
+management’s judgments and assumptions as to future demand requirements and our
+evaluation of market conditions. Demand for our products may fluctuate
+significantly over time, and actual demand and market conditions may be more or
+less favorable than those projected by management. In the event that actual
+demand is lower than originally projected, additional inventory write-downs may
+be required. Estimated inventory write-downs, once established, are not
+reversed until the related inventory has been sold or scrapped, so if actual
+market conditions are more favorable in the fiscal periods subsequent to those
+in which we record significant write-downs, we may have higher gross margins
+when products are sold. 
+Goodwill. Goodwill is
+tested for impairment annually in our fourth fiscal quarter at the reporting
+unit level unless a change in circumstances indicates that more frequent
+impairment analysis is required. We have determined that our reporting units
+for purposes of testing for goodwill impairment are identical to our reportable
+segments for financial reporting purposes. Impairment, if any, is measured
+based on the estimated fair value of the reporting units with the recorded
+goodwill. The fair value of our reporting units is determined by using the
+income approach methodology of valuation which utilizes discounted cash flows.
+The estimated fair value of our reporting units also includes a control
+premium, which is the amount that a buyer is willing to pay over the current
+market price of a company as indicated by the traded price per share (i.e.,
+market capitalization), in order to acquire a controlling interest. Significant
+management judgment is required in the forecasts of future operating results
+that are used in the discounted cash flow method of valuation. In estimating
+future cash flows, we generally use the financial assumptions in our current
+budget and our current strategic plan, subject to modification as considered
+necessary, including sales and expense growth rates and the discount rates we
+estimate to represent our cost of funds. It is possible, however, that the
+plans and estimates we use may be incorrect. 
+We
+performed annual impairment assessments of the carrying value of goodwill for
+each of the fiscal years ended March 31, 2010, 2009 and 2008. Based on
+these assessments, we determined that no impairment as of each of these dates
+was indicated as the estimated fair value of each reporting unit exceeded its
+respective carrying value. At March 31, 2010, our Roadway Sensors, Vehicle
+Sensors and Transportation Systems reporting units had goodwill balances of
+$8.2 million, $4.7 million and $14.9 million, respectively. Based on our
+assessment at March 31, 2010, the estimated fair values of our Roadway
+Sensors, Vehicle Sensors and Transportation Systems reporting units were
+approximately 73%, 79% and 18%, respectively, greater than their respective
+carrying values. Among other factors, the fair value of our Transportation
+Systems reporting unit in the future could be adversely impacted by (i) our
+inability to maintain adequate utilization of our workforce, (ii) our failure
+to successfully bid on new contracts and renew existing contracts and (iii) government
+budgetary issues and related delays in spending. Likewise, if our actual
+financial results, or the plans and estimates used in future goodwill
+impairment analyses, are lower than the original estimates used to assess for
+impairment of our goodwill, we could incur future goodwill impairment charges
+in our Transportation Systems or other reporting units. 
+Warranty. We generally
+provide a one to three year warranty from the original invoice date on all
+products, materials and workmanship. Defective products are either repaired or
+replaced, at our option, upon meeting certain criteria. We accrue a provision
+for the estimated costs that may be incurred for product warranties relating to
+a product as a component of cost of sales at the time revenue for that product
+is recognized. The accrued warranty provision is included within accrued
+expenses on the accompanying consolidated balance sheets. Should our actual
+experience of warranty returns be higher than anticipated, additional warranty
+reserves may be required, which would adversely affect our product gross profit
+and our operating results. 
+Income
+Taxes. On a quarterly basis, we assess the likelihood that our deferred tax asset
+balance will be recovered from future taxable income. Realization of deferred
+tax assets (such as net operating loss carryforwards) is dependent on future
+taxable earnings and is therefore uncertain. To the extent we believe that
+recovery is not likely, we establish a valuation allowance to reduce our
+deferred tax assets to amounts that we believe are more likely than not to be
+realized, which increases our income tax expense in the period such
+determination is made. 
+19 
+Table of Contents 
+On
+an interim basis, we estimate what our anticipated annual effective tax rate
+will be, while also separately considering applicable discrete and other
+non-recurring items, and record a quarterly income tax provision in accordance
+with this anticipated rate. As the fiscal year progresses, we refine our
+estimates based upon actual events and financial results during the year. This
+estimation process can result in significant changes to our expected effective
+tax rate. When this occurs, we adjust our income tax provision during the
+quarter in which our estimates are refined so that the year-to-date provision
+reflects the expected annual effective tax rate. These changes, along with
+adjustments to our deferred taxes, among others, may create fluctuations in our
+overall effective tax rate from quarter to quarter. 
+We must review all of our tax positions and make a
+determination as to whether each position is more-likely-than-not to be
+sustained upon examination by regulatory authorities. If a tax position meets
+the more-likely-than-not standard, then the related tax benefit is measured
+based on a cumulative probability analysis of the amount that is more-likely-than-not
+to be realized upon ultimate settlement or disposition of the underlying issue. 
+The
+application of tax laws and regulations is subject to legal and factual
+interpretation, judgment and uncertainty. Tax laws and regulations themselves
+are subject to change as a result of changes in fiscal policy, changes in
+legislation, the evolution of regulations and court rulings. Therefore, the
+actual liability for U.S. or foreign taxes may be materially different
+from our estimates, which could result in the need to record additional tax
+liabilities or potentially reverse previously recorded tax liabilities. 
+Stock-Based
+Compensation . We
+record stock-based compensation in the statement of income as an expense, based
+on the estimated grant date fair value of our stock-based awards, whereby such
+fair values are amortized over the requisite service period. The fair value of
+our common stock option awards is estimated on the grant date using the
+Black-Scholes-Merton (“BSM”) option-pricing formula. While utilizing this model
+meets established requirements, the estimated fair values generated by it may
+not be indicative of the actual fair values of our common stock option awards
+as it does not consider certain factors important to those awards to employees,
+such as continued employment and periodic vesting requirements as well as
+limited transferability. Our assumptions under the BSM formula include the
+following: (i) expected volatilities are based on the historical
+volatility of our stock price, (ii) the expected life of options is
+derived based on the historical life of our options, (iii) the risk-free
+rate for periods within the expected life of the option is based on the U.S.
+Treasury interest rates in effect at the time of grant and (iv) the
+dividend yield assumption is based on our history and expectation of dividend
+payouts. Additionally, we include an estimate of forfeitures in the calculation
+of stock-based compensation expense. Future stock-based compensation expense in
+any particular quarter or year could be affected by changes in our assumptions,
+changes in market conditions, or to the extent that we grant additional
+stock-based awards. Additionally, if there are any modifications or
+cancellations of the underlying unvested stock-based awards, we may be required
+to accelerate, increase or cancel any remaining unearned stock-based
+compensation expense. 
+Recent Accounting
+Pronouncements 
+Refer to Note 1 of Notes to Consolidated Financial
+Statements, included in Part IV, Item 15 of this report for a discussion
+of recent accounting pronouncements. 
+20 
+Table of
+Contents 
+Results of Operations 
+The following table sets
+forth certain statement of income data as a percentage of total net sales and
+contract revenues for the periods indicated. The following table should be read
+in conjunction with Management’s Discussion and Analysis of Financial Condition
+and Results of Operations. 
+Year Ended
+March 31, 
+2010 
+2009 
+2008 
+Net sales and contract revenues: 
+Net sales 
+54.5 
+% 
+55.4 
+% 
+61.9 
+% 
+Contract revenues 
+45.5 
+44.6 
+38.1 
+Total net sales and contract revenues 
+100.0 
+% 
+100.0 
+% 
+100.0 
+% 
+Costs of net sales and contract revenues: 
+Cost of net sales 
+28.4 
+29.3 
+31.5 
+Cost of contract revenues 
+30.0 
+30.4 
+25.1 
+Gross profit 
+41.6 
+40.3 
+43.4 
+Operating expenses: 
+Selling, general and administrative 
+29.3 
+26.0 
+26.5 
+Research and development 
+6.3 
+5.8 
+5.5 
+Amortization of intangible assets 
+0.3 
+0.2 
+0.2 
+Total operating expenses 
+35.9 
+32.0 
+32.2 
+Operating income 
+5.7 
+8.2 
+11.2 
+Non-operating income (expense): 
+Other income, net 
+0.1 
+0.2 
+0.4 
+Interest expense, net 
+(0.5 
+) 
+(0.9 
+) 
+(2.0 
+) 
+Income before income taxes 
+5.3 
+7.5 
+9.6 
+Benefit (provision) for income taxes 
+(1.5 
+) 
+7.6 
+9.1 
+Net income 
+3.8 
+% 
+15.1 
+% 
+18.7 
+% 
+Analysis
+of Fiscal 2010, Fiscal 2009 and Fiscal 2008 Results of Operations 
+Net
+Sales and Contract Revenues . Net sales are comprised of product sales from our
+Roadway Sensors and Vehicle Sensors segments, as well as contract engineering
+revenue and royalty revenue generated from our Vehicle Sensors
+segment. Contract revenues consist entirely of Transportation Systems contract
+revenues, which are generated from systems integration and ITS engineering and
+consulting services primarily with federal, state, county and municipal
+agencies. 
+21 
+Table of Contents 
+The following
+tables present details of our net sales and contract revenues for Fiscal 2010
+compared to Fiscal 2009, and Fiscal 2009 compared to Fiscal 2008: 
+Fiscal 
+Fiscal 
+% 
+2010 
+2009 
+Decrease 
+Change 
+(In thousands, except percentages) 
+Roadway Sensors 
+$ 
+25,341 
+$ 
+27,197 
+$ 
+(1,856 
+) 
+(6.8 
+)% 
+Vehicle Sensors 
+6,309 
+11,230 
+(4,921 
+) 
+(43.8 
+) 
+Net sales 
+31,650 
+38,427 
+(6,777 
+) 
+(17.6 
+) 
+Contract revenues 
+26,413 
+30,932 
+(4,519 
+) 
+(14.6 
+) 
+Total net sales and contract revenues 
+$ 
+58,063 
+$ 
+69,359 
+$ 
+(11,296 
+) 
+(16.3 
+) 
+Fiscal 
+Fiscal 
+Increase 
+% 
+2009 
+2008 
+(Decrease) 
+Change 
+(In thousands, except percentages) 
+Roadway Sensors 
+$ 
+27,197 
+$ 
+28,452 
+$ 
+(1,255 
+) 
+(4.4 
+)% 
+Vehicle Sensors 
+11,230 
+11,874 
+(644 
+) 
+(5.4 
+) 
+Net sales 
+38,427 
+40,326 
+(1,899 
+) 
+(4.7 
+) 
+Contract revenues 
+30,932 
+24,837 
+6,095 
+24.5 
+Total net sales and contract revenues 
+$ 
+69,359 
+$ 
+65,163 
+$ 
+4,196 
+6.4 
+We currently have
+a diverse customer base with no individual customer representing greater than
+10% of our total annual net sales and contract revenues for Fiscal 2010, Fiscal
+2009 or Fiscal 2008. 
+Roadway
+Sensors 
+The
+majority of Roadway Sensors net sales were derived from sales within North
+America. The sequential decreases in Roadway Sensors net sales in Fiscal 2010
+as compared to Fiscal 2009, and likewise Fiscal 2009 as compared to Fiscal
+2008, were mainly due to the ongoing effects of reduced and delayed spending on
+infrastructure projects, in part due to the decline in commercial and
+residential construction as well as state and local government budgetary
+pressures, and increased competitors in the market. While we are cautiously
+optimistic heading into Fiscal 2011, we expect the challenging economic factors
+discussed above, among others, may continue to adversely impact our Roadway
+Sensors net sales for at least the next few fiscal quarters. 
+Vehicle Sensors 
+The largest element of
+Vehicle Sensors net sales was sales of our LDW systems to the heavy truck market,
+which aggregated approximately $5.6 million in Fiscal 2010, $9.9 million in
+Fiscal 2009 and $10.0 million in Fiscal 2008. Vehicle Sensors net sales have
+sequentially decreased over the last two fiscal years primarily due to the
+slowdown in our LDW unit shipments to each of our key markets, which began in
+the fourth quarter of Fiscal 2009. Although we saw an encouraging increase in
+net sales in the second half of Fiscal 2010 as compared to the immediately
+preceding quarters, which resulted primarily from significant sales to one of
+our U.S. truck fleet customers in the fourth quarter, we cannot assure you that
+such sales levels from this or other customers will recur in subsequent
+periods. We also continue to experience overall softness in our LDW unit sales
+to the North American truck market and to our European and Asian OEM customers.
+We believe this is driven largely by lower new heavy truck sales in general, as
+well as the general slowdown in the U.S. and worldwide credit markets and
+continued weakness and uncertainty in the overall global economy. We anticipate
+that Vehicle Sensors unit sales beyond Fiscal 2010 could continue to be
+adversely impacted as a result of the overall decline in sales of heavy trucks
+globally and by slower than expected adoption rates of our LDW system by
+European and Asian OEMs and North American heavy truck fleets. Additionally,
+future unit sales of LDW systems and unit pricing could be adversely impacted
+as a result of increased competition in this market. The increase in
+competition in the current fiscal year contributed to a division of an
+international heavy truck customer sourcing future primary LDW unit sales to a
+competitor for a specific geographic region. 
+Also included in Vehicle
+Sensors net sales are revenues from contract engineering services and royalty
+revenues in the passenger car market that are derived from our strategic
+relationship with Valeo, which aggregated approximately $685,000, $1.3 million
+and $1.9 million for the fiscal years ended March 31, 2010, 2009 and 2008,
+respectively. We have experienced year-over-year decreases in contract
+engineering services provided to Valeo as the pertinent engineering development
+activities have generally reached maturity for the related vehicle platforms
+that currently incorporate our LDW system. Our LDW systems are currently
+offered as an option on three Infiniti models, with a fourth model expected by
+the summer of 2010. While Valeo is promoting our LDW systems to other passenger
+car OEMs, we cannot assure you that Valeo will be successful in these efforts. 
+22 
+Table of Contents 
+Contract Revenues 
+Contract
+revenues are derived from our Transportation Systems segment and are primarily
+dependent upon the continued availability of funding at both the state and
+federal levels from the various departments of transportation. The decrease in
+contract revenues in Fiscal 2010 as compared to Fiscal 2009 was due primarily
+to delays or reductions in funding for certain of our projects, particularly in
+the Southeast region of the U.S. and in our private planning group, which
+focuses on private development consulting. The decrease is also attributable to
+the timing differences on certain of our larger contracts, which contained a
+higher amount of sub-consultant revenue in Fiscal 2009, but such contracts were
+mostly completed by the end of Fiscal 2009 and were not replaced with similar
+such contracts in the current fiscal year. In the future, we plan to pursue
+large contracts that may contain significant sub-consulting content, which will
+likely contribute to variability in the timing and amount of our contract
+revenues from period to period. 
+During
+Fiscal 2010, we began work on our first two overseas contract awards in Abu
+Dhabi and Dubai, for which we have recognized contract revenues to date of
+approximately $300,000. We plan to continue to pursue additional international
+opportunities for our Transportation Systems segment in the future. Among other
+factors, we believe the ability of our Transportation Systems segment to grow
+and successfully win and service new contracts will be highly dependent upon
+our continued success in recruiting and retaining qualified personnel. 
+The Fiscal 2009 increase
+in contract revenues, as compared to Fiscal 2008, was largely a result of our
+increased sales and marketing activity across the U.S., resulting in certain
+significant new contracts that were awarded to us in Fiscal 2009. Certain of
+these new contracts contained a higher than usual amount of sub-consulting
+content, which was primarily concentrated in our contract revenues in the
+fourth quarter of Fiscal 2009. 
+Gross
+Profit . The
+following tables present details of our gross profit for Fiscal 2010 compared
+to Fiscal 2009, and Fiscal 2009 compared to Fiscal 2008: 
+Fiscal 
+Fiscal 
+% 
+2010 
+2009 
+Decrease 
+Change 
+(In thousands, except percentages) 
+Total gross profit 
+$ 
+24,159 
+$ 
+27,919 
+$ 
+(3,760 
+) 
+(13.5 
+)% 
+Total gross profit as a % of total net sales and contract
+revenues 
+41.6 
+% 
+40.3 
+% 
+Gross profit as a % of net sales 
+47.9 
+% 
+47.1 
+% 
+Gross profit as a % of contract revenues 
+34.1 
+% 
+31.8 
+% 
+Fiscal 
+Fiscal 
+% 
+2009 
+2008 
+Decrease 
+Change 
+(In thousands, except percentages) 
+Total gross profit 
+$ 
+27,919 
+$ 
+28,297 
+$ 
+(378 
+) 
+(1.3 
+)% 
+Total gross profit as a % of total net sales and contract
+revenues 
+40.3 
+% 
+43.4 
+% 
+Gross profit as a % of net sales 
+47.1 
+% 
+49.2 
+% 
+Gross profit as a % of contract revenues 
+31.8 
+% 
+34.1 
+% 
+The
+decrease in our total gross profit for Fiscal 2010 as compared to Fiscal 2009
+was generally commensurate with the overall decline in total net sales and
+contract revenues, as discussed above. Our total gross profit as a percent of
+total net sales and contract revenues for Fiscal 2010 increased slightly
+compared to Fiscal 2009 primarily due to higher margins from our net sales,
+particularly Roadway Sensors, as we realized cost savings due to lower costs of
+materials driven by improvements in our supply chain management, which we
+anticipate will continue in the future. The increase was also attributable, to
+a lesser extent, to the improvement in our Transportation Systems margins in
+Fiscal 2010, as discussed further below. 
+The
+slight increase in gross profit as a percent of net sales in Fiscal 2010 as
+compared to Fiscal 2009 was due to certain materials cost savings, as discussed
+above, and a favorable customer mix weighted more toward direct sales. We
+generally enjoy higher gross margins on direct sales as compared to dealer and
+aftermarket sales. The increase was partially offset during the year by
+decreased gross margins in Vehicle Sensors, which was largely driven by lower
+overhead absorption due to the decline in sales, along with an increase in
+certain estimates for additional excess and obsolete inventory provisions. The
+decrease in gross profit as a percent 
+23 
+Table of
+Contents 
+of net sales in Fiscal 2009
+as compared to Fiscal 2008 was primarily a result of decreased gross profit in
+Roadway Sensors and was largely driven by an unfavorable customer mix weighted
+more toward dealer than direct sales in Fiscal 2009. Gross profit as a
+percentage of net sales can fluctuate in any specific quarter or year based on,
+among other factors, customer and product mix, competitive pricing requirements,
+product warranty costs and provisions for excess and obsolete inventories, as
+well as possible shifts of engineering resources from development activities to
+sustaining activities, which we record as cost of goods sold. 
+We
+recognize contract revenues and related gross profit using percentage of
+completion contract accounting, and the underlying mix of contract activity
+affects the related gross profit recognized in any given period. The increase
+in gross profit as a percent of contract revenues in Fiscal 2010 compared to
+Fiscal 2009 was primarily due to a contract mix weighted more toward higher
+margin contracts in the current fiscal year. Our higher margin contracts often
+contain a comparatively lower proportion of sub-consulting revenues associated
+with them. Conversely, a larger portion of our Fiscal 2009 contract revenues
+contained higher sub-consulting content, as compared to Fiscal 2008, and thus
+contributed to overall lower margins. Particularly, we experienced an
+abnormally high level of sub-consulting content related to certain new
+contracts during the fourth quarter of Fiscal 2009, which contributed both to
+the overall increase in contract revenues and a decrease in our gross profit.
+In the near term, we expect our sub-consulting content as a percentage of total
+contract revenues to be generally in line with those experienced in Fiscal
+2010; however, due to the variability and timing of our contracts, it has
+become increasingly difficult to accurately predict the sub-consulting content
+in our Transportation Systems contracts in future periods. 
+Selling, General and Administrative Expense 
+The
+following table presents selling, general and administrative expense for Fiscal
+2010 and Fiscal 2009: 
+Fiscal 2010 
+Fiscal 2009 
+% of Net 
+% of Net 
+Sales and 
+Sales and 
+Contract 
+Contract 
+Increase 
+% 
+Amount 
+Revenues 
+Amount 
+Revenues 
+(Decrease) 
+Change 
+(In thousands, except percentages) 
+Salary
+and personnel-related 
+$ 
+11,262 
+19.4 
+% 
+$ 
+11,949 
+17.2 
+% 
+$ 
+(687 
+) 
+(5.7 
+)% 
+Facilities,
+insurance and supplies 
+2,444 
+4.2 
+2,378 
+3.4 
+66 
+2.8 
+Travel
+and conferences 
+1,488 
+2.6 
+1,563 
+2.3 
+(75 
+) 
+(4.8 
+) 
+Professional
+and outside services 
+1,038 
+1.8 
+1,302 
+1.9 
+(264 
+) 
+(20.3 
+) 
+Other 
+772 
+1.3 
+843 
+1.2 
+(71 
+) 
+(8.4 
+) 
+Selling,
+general and administrative 
+$ 
+17,004 
+29.3 
+% 
+$ 
+18,035 
+26.0 
+% 
+$ 
+(1,031 
+) 
+(5.7 
+) 
+The
+decrease in selling, general and administrative expenses in Fiscal 2010 as
+compared to Fiscal 2009 was primarily due to (i) our overall reduction in
+headcount from March 31, 2009; (ii) lower accruals for bonuses and
+other incentive compensation primarily due to lower sales and operating profit
+in the current fiscal year; and (iii) the suspension of our matching
+contributions under our 401(k) plan effective July 1, 2009. We also
+reduced our professional and outside services expenses during the current
+fiscal year primarily through our efforts to conserve costs and scale back our
+usage of such services, along with various efficiencies gained in our internal
+control assessment and other financial reporting obligations. In Fiscal 2011,
+we are currently scheduled to be subject to the requirement that our
+independent registered public accounting firm provide an attestation on the
+effectiveness of our internal control over financial reporting, which we expect
+will increase our professional and outside services expenses. 
+24 
+Table of Contents 
+The
+following table presents selling, general and administrative expense for Fiscal
+2009 and 2008: 
+Fiscal 2009 
+Fiscal 2008 
+% of Net 
+% of Net 
+Sales and 
+Sales and 
+Contract 
+Contract 
+Increase 
+% 
+Amount 
+Revenues 
+Amount 
+Revenues 
+(Decrease) 
+Change 
+(In thousands, except percentages) 
+Salary
+and personnel-related 
+$ 
+11,949 
+17.2 
+% 
+$ 
+10,916 
+16.8 
+% 
+$ 
+1,033 
+9.5 
+% 
+Facilities,
+insurance and supplies 
+2,378 
+3.4 
+2,254 
+3.5 
+124 
+5.5 
+Travel
+and conferences 
+1,563 
+2.3 
+1,323 
+2.0 
+240 
+18.1 
+Professional
+and outside services 
+1,302 
+1.9 
+1,734 
+2.7 
+(432 
+) 
+(24.9 
+) 
+Other 
+843 
+1.2 
+1,062 
+1.6 
+(219 
+) 
+(20.6 
+) 
+Selling,
+general and administrative 
+$ 
+18,035 
+26.0 
+% 
+$ 
+17,289 
+26.5 
+% 
+$ 
+746 
+4.3 
+The
+overall increase in selling, general and administrative expenses in Fiscal 2009
+was primarily driven by higher selling expenses in our Transportation Systems
+segment as a result of a shift in certain of our labor resources from
+project-related activities to sales and marketing efforts, aimed at capturing
+additional contract backlog. This resulted in an increase in this segment’s
+sales and marketing expenses to $2.8 million for Fiscal 2009 compared to $2.0
+million for Fiscal 2008. Our professional and outside services expenses decreased
+in Fiscal 2009 primarily due to our efforts to conserve costs and scale back
+our usage of certain outside and professional services, as well as various
+efficiencies gained in our internal control assessment and other financial
+reporting obligations in that year. 
+Research and Development Expense 
+The
+following table presents research and development expense for Fiscal 2010 and
+Fiscal 2009: 
+Fiscal 2010 
+Fiscal 2009 
+% of Net 
+% of Net 
+Sales and 
+Sales and 
+Contract 
+Contract 
+% 
+Amount 
+Revenues 
+Amount 
+Revenues 
+Decrease 
+Change 
+(In thousands, except percentages) 
+Salary
+and personnel-related 
+$ 
+2,655 
+4.6 
+% 
+$ 
+2,748 
+4.0 
+% 
+$ 
+(93 
+) 
+(3.4 
+)% 
+Facilties,
+development and supplies 
+883 
+1.5 
+1,018 
+1.5 
+(135 
+) 
+(13.3 
+) 
+Other 
+140 
+0.2 
+264 
+0.4 
+(124 
+) 
+(47.0 
+) 
+Research
+and development 
+$ 
+3,678 
+6.3 
+% 
+$ 
+4,030 
+5.8 
+% 
+$ 
+(352 
+) 
+(8.7 
+) 
+The
+decrease in research and development expense in Fiscal 2010 compared to Fiscal
+2009 was primarily due to lower overall engineering headcount and a more
+efficient engineering structure as we shifted our focus to new product
+development from a historical focus on new customer qualification and
+manufacturing support. We believe research and development activities are
+crucial to our ability to continue to be a leader in our markets. For
+competitive reasons, we closely guard the confidentiality of specific
+development projects. We currently expect our total research and development
+expenditures for Fiscal 2011 to be slightly higher in absolute dollars than
+those for Fiscal 2010. 
+25 
+Table of Contents 
+The
+following table presents research and development expense for Fiscal 2009 and
+2008: 
+Fiscal 2009 
+Fiscal 2008 
+% of Net 
+% of Net 
+Sales and 
+Sales and 
+Contract 
+Contract 
+Increase 
+% 
+Amount 
+Revenues 
+Amount 
+Revenues 
+(Decrease) 
+Change 
+(In thousands, except percentages) 
+Salary
+and personnel-related 
+$ 
+2,748 
+4.0 
+% 
+$ 
+2,294 
+3.5 
+% 
+$ 
+454 
+19.8 
+% 
+Facilties,
+development and supplies 
+1,018 
+1.5 
+1,019 
+1.6 
+(1 
+) 
+(0.1 
+) 
+Other 
+264 
+0.4 
+253 
+0.4 
+11 
+4.3 
+Research
+and development 
+$ 
+4,030 
+5.8 
+% 
+$ 
+3,566 
+5.5 
+% 
+$ 
+464 
+13.0 
+The
+increase in research and development expense in Fiscal 2009 compared to Fiscal
+2008 was primarily due to increased research and development activities in
+Roadway Sensors aimed at accelerating the time to market of certain new
+products which were introduced in Fiscal 2009. 
+Other
+Income, Net 
+Other
+income, net in Fiscal 2010 was $44,000 and primarily consisted of foreign
+currency transaction gains and the net decrease in the fair value of certain
+outstanding warrants. See Note 8 of Notes to Consolidated Financial Statements,
+included in Part IV, Item 15 of this report, for additional discussion
+regarding the fair value of our warrants. 
+Other
+income, net in Fiscal 2009 was $116,000 and includes the net gain of $50,000
+that we recognized in connection with the early retirement of certain of our
+convertible debentures, as well as net foreign currency transaction gains and
+other miscellaneous income. Other income, net in Fiscal 2008 was $252,000 and
+primarily reflected the net gain of $224,000 we recognized in connection with
+the early retirement of certain convertible debentures. See Note 4 of Notes to
+Consolidated Financial Statements for additional discussion regarding the
+retirement of our convertible debentures. 
+Interest
+Expense, Net 
+Net
+interest expense was $264,000, $646,000 and $1.3 million in Fiscal 2010, 2009
+and 2008, respectively. The sequential decreases were primarily due to our
+lower overall level of borrowings and lower interest rates in the current
+years. 
+Income
+Taxes 
+The following table
+presents our benefit (provision) for income taxes for Fiscal 2010, Fiscal 2009
+and Fiscal 2008: 
+Year Ended March 31, 
+2010 
+2009 
+2008 
+(In thousands, except percentages) 
+Benefit
+(provision) for income taxes 
+$ 
+(895 
+) 
+$ 
+5,297 
+$ 
+5,900 
+Effective
+tax rate 
+28.9 
+% 
+(102.3 
+)% 
+(94.2 
+)% 
+Our effective tax rate
+for Fiscal 2010 was favorably impacted primarily by the recognition of
+approximately $414,000 of unrecognized tax benefits during the year due to the
+expiration of certain federal and state statutes in various jurisdictions. The
+income tax benefits recorded in Fiscal 2009 and Fiscal 2008 were primarily the
+result of a decrease in the valuation allowance recorded against our deferred
+tax assets as a result of changes in estimates of the future realizability of
+these assets. As we update our estimates in future periods, adjustments to our
+deferred tax asset and valuation allowance may be necessary. We anticipate this
+will cause our future overall effective tax rate in any given period to fluctuate
+from prior effective tax rates and statutory tax rates. We utilize the
+liability method of accounting for income taxes. We record net deferred tax
+assets to the extent that we believe these assets will more likely than not be
+realized. In making such determination, we consider all available positive and
+negative evidence, including, but not limited to, scheduled reversals of
+deferred tax liabilities, projected future taxable income, tax planning
+strategies and recent financial performance. 
+26 
+Table of Contents 
+At March 31, 2010, we had $38.5 million of federal net operating
+loss carryforwards and $18.4 million of state net operating loss
+carryforwards that begin to expire in 2019 and 2013, respectively. Due to
+changes in stock ownership, our federal net operating loss carryforwards and
+other federal attributes are subject to a Section 382 annual limitation.
+Although the impact cannot be precisely determined at this time, we believe
+that our net operating loss carryforwards will cause us to have future income
+tax payments that are substantially lower than the income tax liability
+calculated using statutory tax rates. 
+Liquidity
+and Capital Resources 
+Cash Flows 
+We have historically
+financed our operations with a combination of cash flows from operations,
+borrowings under credit facilities and the sale of equity securities. We
+currently rely on cash flows from operations and the availability of borrowings
+on a line of credit facility to fund our operations, which we believe to be
+sufficient to fund our operations for at least the next twelve months. However,
+we may need to raise additional capital to fund potential future acquisitions and
+our future growth. We may raise such funds by selling equity or debt securities
+to the public or to selected investors, or by borrowing money from financial
+institutions. If we raise additional funds by issuing equity or convertible
+debt securities, the ownership percentage of existing stockholders would likely
+be reduced. 
+At March 31, 2010, we
+had $22.6 million in working capital, which included no borrowings on our $12.0
+million line of credit and $10.4 million in cash and cash equivalents. This
+compares to working capital of $20.6 million at March 31, 2009, which
+included no borrowings on our line of credit and $6.4 million in cash and cash
+equivalents. 
+The following table
+summarizes our cash flows for Fiscal 2010, Fiscal 2009 and Fiscal 2008: 
+Year Ended March 31, 
+2010 
+2009 
+2008 
+(In thousands) 
+Net cash provided by (used in): 
+Operating
+activities 
+$ 
+6,484 
+$ 
+6,390 
+$ 
+7,579 
+Investing
+activities 
+(594 
+) 
+(795 
+) 
+(739 
+) 
+Financing
+activities 
+(1,857 
+) 
+413 
+(6,454 
+) 
+Operating Activities. Cash provided by our operations in Fiscal
+2010 was primarily the result of (i) our Fiscal 2010 net income of $2.2
+million; (ii) $2.5 million in non-cash items within the statement of
+income, primarily consisting of adjustments to our deferred tax assets of $1.0
+million, depreciation expense of $986,000 and stock-based compensation expense
+of $375,000; and (iii) $1.7 million in cash resulting from changes in our
+operating assets and liabilities during the year. 
+Our
+net accounts receivable decreased approximately $1.1 million from March 31,
+2009 to March 31, 2010 due in part to our lower net sales and contract
+revenues in Fiscal 2010 as compared to Fiscal 2009 levels. During the current
+fiscal year, we have also generally been successful in collecting our
+outstanding receivables within our expected payment terms. In the future, our
+accounts receivable could increase if customers delay their payments or if we
+grant extended payment terms to customers, both of which are more likely to
+occur during challenging economic times when our customers may face issues
+gaining sufficient credit on a timely basis or on acceptable terms. 
+Inventories
+decreased approximately $3.0 million from March 31, 2009 to March 31,
+2010 as we worked through higher inventory levels on-hand as of March 31,
+2009, which were partially due to the introduction of new Roadway Sensors
+products and the acquisition of various components that were discontinued by
+the manufacturer. During the current fiscal year, we have also focused on
+reducing our inventory purchases to reflect the overall reduction in our net
+sales and the ongoing economic slowdown. In the future, our inventory levels
+are likely to continue to be determined based upon, among other factors, the
+level of purchase orders we receive from our customers, the stage at which our
+products are in their respective product life cycles, and competitive
+situations in the marketplace. We attempt to balance such considerations
+against risk of obsolescence or potentially excess inventory levels. 
+Accounts
+payable decreased approximately $1.7 million from March 31, 2009 to March 31,
+2010 largely due to the decrease in inventory purchases throughout Fiscal 2010
+as compared to the prior fiscal year. The general timing of inventory and other
+purchases and vendor payments also contributed to the year-over-year decrease
+in our accounts payable. 
+Cash provided by our
+operations in Fiscal 2009 was primarily the result of our Fiscal 2009 net
+income of $10.5 million adjusted for $3.7 million of net non-cash items within
+the statement of income, which was comprised primarily of adjustments to our
+deferred tax balances of $5.4 million, offset slightly by depreciation expense
+of $1.0 million and stock-based compensation, amortization and other items
+totaling $642,000. 
+27 
+Table of Contents 
+Cash provided by our
+operations in Fiscal 2008 was primarily the result of our Fiscal 2008 net
+income of $12.2 million and $1.6 million in net cash provided by changes in
+operating assets and liabilities. These were partially offset by approximately
+$6.2 million in net non-cash items within the statement of income, which
+included adjustments to our deferred tax balances of $7.3 million, offset
+slightly by depreciation, stock compensation, amortization and other items
+totaling $1.1 million. 
+Investing Activities. Our investing activities for
+Fiscal 2010 consisted of purchases of property and equipment of $294,000, as
+well as $300,000 representing the initial payment for the acquisition of
+Hamilton Signal, Inc. In April 2010, we subsequently made our second
+payment of $106,000 for the purchase of Hamilton Signal, and we expect to make
+the final payment of approximately $112,000 in April 2011. For further
+information on our acquisition of Hamilton Signal, Inc., refer to Note 3
+of Notes to Consolidated Financial Statements included in Part IV, Item 15
+of this report 
+Cash used in investing
+activities for Fiscal 2009 and Fiscal 2008 each consisted of purchases of
+certain property and equipment of $795,000 and $739,000, respectively. 
+Financing Activities. Net cash used in financing
+activities during Fiscal 2010 was the result of net payments on our long-term
+debt of $2.0 million, which included our contractual monthly principal payments
+as well as an additional principal payment of $500,000 made in November 2009,
+as further discussed below under “Borrowings.” The net payments on our
+long-term debt were partially offset by $143,000 in proceeds received from the
+exercise of outstanding stock options to purchase shares of our common stock.
+Net cash provided by financing activities in Fiscal 2009 was the result of
+$900,000 in cash inflows from the exercise of stock options to purchase our
+common stock, partially offset by net payments on our borrowings of $500,000.
+Net cash used in financing activities in Fiscal 2008 was the result of net
+payments on our borrowings of $8.0 million, partially offset by cash inflows of
+$1.5 million from the exercise of outstanding stock options and warrants to
+purchase our common stock. 
+Borrowings 
+In October 2008,
+we entered into a $19.5 million credit facility with California Bank &
+Trust, which provides for a two-year revolving line of credit with borrowings
+of up to $12.0 million and a $7.5 million 48-month term note (discussed below).
+Interest on borrowed amounts under the revolving line of credit are payable
+monthly at a rate equal to the current stated prime rate (3.25% at March 31,
+2010) up to the current stated prime rate plus 0.50%, depending on aggregate
+deposit balances maintained at the bank in relation to the total loan
+commitment under the credit facility. We are obligated to pay an unused line
+fee of 0.25% per annum applied to the average unused portion of the revolving
+line of credit during the preceding month. The revolving line of credit does
+not contain any early termination fees and is secured by substantially all of
+our assets. As of March 31, 2010, no amounts were outstanding under the
+revolving line of credit portion of the facility. Availability under this line
+of credit may be reduced or otherwise limited as a result of our obligations to
+comply with certain financial covenants, as described further below. 
+As of March 31, 2010, we had outstanding
+borrowings of approximately $5.3 million under the term note included in our
+credit facility. Principal payments under this term note are required to be
+repaid in 48 monthly installments of $152,000 commencing on June 1, 2009.
+Additionally, beginning on November 1, 2009, and on November 1 of
+each year thereafter, we are required to repay additional principal of up to
+$500,000, calculated based on certain financial measures, as further defined in
+the loan agreement. These additional principal payments effectively reduce the
+total number of monthly installments necessary to repay the term note. Interest
+on the term note is payable monthly at a rate equal to the current stated prime
+rate plus 0.50% up to the current stated prime rate plus 1.00%, depending on
+aggregate deposit balances maintained at the bank in relation to the total loan
+commitment under the credit facility. The term note contains no early
+termination fees and, along with our revolving line of credit discussed above,
+is secured by substantially all of our assets. 
+In connection with
+our credit facility and loan agreement with California Bank & Trust,
+we are also required to comply with certain quarterly financial covenants.
+These include achieving ratios for working capital and debt service, as well as
+maintaining a level of profitability, all of which are further defined in the
+agreement. While we believe we are currently in compliance with all such
+financial covenants and expect to maintain compliance for the foreseeable
+future, we cannot assure you that we will not violate one or more covenants in
+the future. If we were to be in violation of covenants under this agreement,
+our lender could choose to accelerate payment on all outstanding loan balances
+and pursue its security interest in our assets. In this event, we cannot assure
+you that we would be able to quickly obtain equivalent or suitable replacement
+financing on acceptable terms, or at all. If we were not able to secure
+alternative sources of financing, such acceleration would have a material
+adverse impact on our business and financial condition. 
+Off Balance Sheet Arrangements 
+At March 31, 2010,
+we had outstanding warrants to purchase an aggregate of 246,250 shares of
+our common stock at an exercise price of $3.25 per share that are callable by
+us, for a purchase price of $0.01 per share, if the market price of our common
+stock trades for 20 consecutive days at a price equal to or greater than $6.50
+per share. These warrants are scheduled to expire in February 2011. We
+also had outstanding warrants to purchase an aggregate of 75,000 shares of
+our common stock at an exercise price of $5.00 per share that are callable by
+us, for an aggregate purchase price of $1.00, if the market price of our common
+stock trades for 20 consecutive days at a price equal to or greater than $7.50
+per share. These warrants are scheduled to expire in July 2010. 
+28 
+Table of Contents 
+In connection with the
+issuance of warrants to purchase 246,250 shares of our common stock at $3.25
+per share (discussed above), we are a party to a registration rights agreement
+that contains provisions under which we could be subjected to liquidated
+damages should we fail to maintain effective registration statements for the
+shares of common stock issuable upon exercise of certain underlying warrants.
+Through March 31, 2009, these warrants were accounted for within equity in
+our consolidated balance sheets and, accordingly, no liabilities were recorded
+in connection therewith. Beginning April 1, 2009, as further discussed at
+Note 8 of Notes to Consolidated Financial Statements included in Part IV,
+Item 15 of this report, because these warrants contain a provision for possible
+future adjustments to either the exercise price and/or number of shares to be
+issued upon exercise, we began recognizing these warrants as liabilities in our
+consolidated balance sheet with changes in their fair value recorded in our
+consolidated statement of income. As of the date of this filing, no liquidated
+damages are payable under the provisions of the registration rights agreement
+associated with these warrants. 
+Other than our operating
+leases, which are further described at Note 6 of Notes to Consolidated
+Financial Statements, included in Part IV, Item 15 of this report, we do
+not believe we have any other material off balance sheet arrangements at March 31,
+2010. 
+Seasonality 
+We
+have historically experienced seasonality, particularly with respect to our
+Roadway Sensors net sales in the third and fourth fiscal quarters due to a
+reduction in road construction and repairs during the winter months due to
+inclement weather conditions. 
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
+Interest Rate Risk 
+Our exposure to interest rate risk is limited to our
+line of credit and our bank term note. Our line of credit bears interest equal
+to the prevailing prime rate (3.25% at March 31, 2010) plus 0% to 1.0%. We
+do not believe that a 10% increase in the interest rate on our line of credit
+or term note would have a material impact on our financial position, operating
+results or cash flows. In addition, we believe that the carrying value of our
+outstanding debt under our credit facility approximates fair value. 
+Foreign Currency Risk 
+To
+date, a small portion of our net sales have been denominated in Euros. Gains or
+losses from foreign currency remeasurement are included in other income in our
+consolidated financial statements and to date have not been significant. We do
+not believe we are currently exposed to any material risk of loss from currency
+exchange fluctuations. We do not currently purchase derivative financial
+instruments to hedge foreign currency exchange risk, but may do so in the
+future. 
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+The financial statements
+and supplementary data required by Regulation S-X are included in Part IV,
+Item 15 of this report. 
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
+DISCLOSURE 
+None. 
+29 
+Table of Contents 
+ITEM 9A(T). CONTROLS AND PROCEDURES 
+(a) Evaluation of
+disclosure controls and procedures. In accordance with Rule 13a-15(b) of the
+Securities Exchange Act of 1934, as of the end of the period covered by this
+Annual Report on Form 10-K, management evaluated, with the participation
+of the our President and Chief Executive Officer and the Chief Financial
+Officer, the effectiveness of the design and operation of our disclosure
+controls and procedures (as defined in Rule 13a-15(e) under the
+Exchange Act). Based upon their evaluation of these disclosure controls and
+procedures, the President and Chief Executive Officer and the Chief Financial
+Officer have concluded that our disclosure controls and procedures were
+effective as of the date of such evaluation in ensuring that information
+required to be disclosed in our Exchange Act reports is (1) recorded,
+processed, summarized and reported in a timely manner, and (2) accumulated
+and communicated to management, including the Company’s President and Chief
+Executive Officer and the Chief Financial Officer, as appropriate, to allow
+timely decisions regarding required disclosure. 
+(b) 
+Changes in internal control. There was no
+change in our internal control over financial reporting that occurred during
+the period covered by this Annual Report on Form 10-K that has materially
+affected, or is reasonably likely to materially affect, our internal control
+over financial reporting. 
+Inherent
+Limitations on Internal Control 
+A
+control system, no matter how well conceived and operated, can provide only
+reasonable, not absolute, assurance that the objectives of the control system
+are met. Further, the benefits of controls must be considered relative to their
+costs. Because of the inherent limitations in all control systems, no
+evaluation of controls can provide absolute assurance that all control issues
+and instances of management override or improper acts, if any, have been
+detected. These inherent limitations include the realities that judgments in
+decision making can be faulty, and that breakdowns can occur because of simple
+errors. Additionally, controls can be circumvented by the individual acts of
+some persons, by collusion of two or more people, or by management override of
+the control. The design of any system of controls is also based in part upon
+certain assumptions about the likelihood of future events, and there can be no
+assurance that any design will succeed in achieving its stated goals under all
+potential future conditions. Because of the inherent limitations in a
+cost-effective control system, misstatements due to management override, error
+or improper acts may occur and not be detected. Any resulting misstatement or
+loss may have an adverse and material effect on our business, financial
+condition and results of operations. 
+Management’s Report on Internal
+Control Over Financial Reporting 
+Our management is
+responsible for establishing and maintaining adequate internal control over
+financial reporting. Our internal control system was designed to provide
+reasonable assurance to management and the board of directors regarding the
+effectiveness of our internal control processes over the preparation and fair
+presentation of published financial statements. 
+We have assessed the
+effectiveness of our internal controls over financial reporting as of March 31,
+2010. In making this assessment, we used the criteria set forth by the
+Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in
+Internal Control—Integrated Framework. Based on our assessment, we believe
+that, as of March 31, 2010, our internal control over financial reporting
+is effective based on those criteria. 
+This annual report does not include an attestation
+report of our independent registered public accounting firm regarding internal
+control over financial reporting. Management’s report was not subject to
+attestation by our independent registered public accounting firm pursuant to
+the rules of the SEC that permit us to provide only management’s report in
+this annual report. 
+ITEM 9B . OTHER INFORMATION 
+One of our directors,
+Joel Slutzky, is entering into a trading plan pursuant to Rule 10b5-1(c)(1) of
+the Securities Exchange Act of 1934, as amended, as soon as practicable
+following the filing of this report with the SEC, which trading plan covers an
+aggregate of 96,000 shares of our common stock to be sold by Mr. Slutzky over a
+twelve month period beginning July 1, 2010, at a rate of 8,000 shares per
+month on the first trading day of each month (or as soon as possible
+thereafter) at market price, but not less than 2% below the prior trading day’s
+closing sale price if sold within the first three weeks of the applicable
+month. 
+PART III 
+ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+(a) Identification of Directors. The
+information under the caption “Election of Directors,” appearing in our proxy
+statement for the 2010 Annual Meeting of Stockholders, is incorporated herein
+by reference. 
+(b) Identification of Executive Officers. The
+information under the caption “Executive Compensation and Other Information -
+Executive Officers,” appearing in our proxy statement for the 2010 Annual
+Meeting of Stockholders, is incorporated herein by reference. 
+30 
+Table of Contents 
+(c) Compliance with Section 16(a) of the
+Exchange Act. The information under the caption “Section 16(a) Beneficial
+Ownership Reporting Compliance,” appearing in our proxy statement for the 2010
+Annual Meeting of Stockholders, is incorporated herein by reference. 
+(d) Corporate Governance .
+The information under the caption “Corporate Governance,” appearing in our
+proxy statement for the 2010 Annual Meeting of Stockholders, is incorporated
+herein by reference. 
+(e) Audit Committee .
+The information under the caption “Board Meetings and Committees — Audit
+Committee,” appearing in our proxy statement for the 2010 Annual Meeting of
+Stockholders, is incorporated herein by reference. 
+ITEM 11. EXECUTIVE COMPENSATION 
+The information under the
+caption “Executive Compensation and Other Information,” appearing in our proxy
+statement for the 2010 Annual Meeting of Stockholders, is incorporated herein
+by reference. 
+ITEM 12. SECURITY
+OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
+MATTERS 
+The information under the
+captions “Equity Compensation Plans” and “Principal Stockholders and Common
+Stock Ownership of Certain Beneficial Owners and Management,” appearing in our
+proxy statement for the 2010 Annual Meeting of Stockholders, is incorporated
+herein by reference. 
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
+DIRECTOR INDEPENDENCE 
+The information under the
+captions “Corporate Governance — Director Independence” and “Certain
+Transactions,” appearing in our proxy statement for the 2010 Annual Meeting of
+Stockholders, is incorporated herein by reference. 
+ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES 
+The information under the
+caption “Fees Paid to Independent Registered Public Accounting Firm,” appearing
+in our proxy statement for the 2010 Annual Meeting of Stockholders, is
+incorporated herein by reference. 
+PART IV 
+ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 
+(a) Documents filed as part of this report: 
+1. Financial
+Statements. The following financial statements of Iteris, Inc.
+are included in a separate section of this Annual Report on Form 10-K
+commencing on the pages referenced below: 
+Report of Independent Registered Public Accounting
+Firm 
+35 
+Consolidated
+Balance Sheets as of March 31, 2010 and 2009 
+36 
+Consolidated Statements of Income for the years ended
+March 31, 2010, 2009 and 2008 
+37 
+Consolidated Statements of Stockholders’ Equity and
+Comprehensive Income for the years ended March 31, 2010,
+2009 and 2008 
+38 
+Consolidated Statements of Cash Flows for the years
+ended March 31, 2010, 2009 and 2008 
+39 
+Notes to Consolidated Financial Statements 
+40 
+2. Exhibits . 
+The exhibits listed on the
+accompanying index to exhibits immediately following the financial statements
+are filed as part of, or hereby incorporated by reference into, this report. 
+31 
+Table of Contents 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of
+the Securities Exchange Act of 1934, the registrant has duly caused this report
+to be signed on its behalf by the undersigned, thereunto duly authorized. 
+Dated:
+May 20, 2010 
+ITERIS,
+INC. 
+(Registrant) 
+By
+/S/
+ABBAS MOHADDES 
+Abbas
+Mohaddes 
+Chief
+Executive Officer 
+(Principal
+Executive Officer) 
+32 
+Table of Contents 
+POWER OF
+ATTORNEY 
+We, the undersigned
+officers and directors of Iteris, Inc., do hereby constitute and appoint
+James S. Miele and Abbas Mohaddes, and each of them, our true and lawful
+attorneys-in-fact and agents, each with full power of substitution and
+resubstitution, for him and in his name, place and stead, in any and all
+capacities, to sign any and all amendments to this report, and to file the
+same, with exhibits thereto, and other documents in connection therewith, with
+the Securities and Exchange Commission, granting unto said attorneys-in-fact
+and agents, and each of them, full power and authority to do and perform each
+and every act and thing requisite or necessary to be done in and about the
+premises, as fully to all intents and purposes as he might or could do in
+person, hereby, ratifying and confirming all that each of said
+attorneys-in-fact and agents, or his substitute or substitutes, may lawfully do
+or cause to be done by virtue hereof. 
+Pursuant to the
+requirements of the Securities Exchange Act of 1934, this report has been
+signed below by the following persons on behalf of the registrant in the
+capacities and on the dates indicated: 
+Signature 
+Title 
+Date 
+/s/
+ABBAS MOHADDES 
+Director, President and
+Chief Executive Officer 
+May 20, 2010 
+Abbas
+Mohaddes 
+(principal executive
+officer) 
+/s/
+JAMES S. MIELE 
+Chief Financial Officer 
+May 20, 2010 
+James
+S. Miele 
+(principal financial and
+accounting officer) 
+/s/
+GREGORY A. MINER 
+Chairman of the Board 
+May 20, 2010 
+Gregory
+A. Miner 
+/s/
+RICHARD CHAR 
+Director 
+May 20, 2010 
+Richard
+Char 
+/s/
+KEVIN C. DALY 
+Director 
+May 20, 2010 
+Kevin
+C. Daly, Ph.D. 
+/s/
+JOHN SEAZHOLTZ 
+Director 
+May 20, 2010 
+John
+Seazholtz 
+/s/
+JOEL SLUTZKY 
+Director 
+May 20, 2010 
+Joel
+Slutzky 
+/s/
+THOMAS L. THOMAS 
+Director 
+May 20, 2010 
+Thomas
+L. Thomas 
+33 
+Table of Contents 
+Iteris, Inc. 
+Index to Consolidated Financial Statements 
+Report
+of Independent Registered Public Accounting Firm 
+35 
+Consolidated
+Balance Sheets as of March 31, 2010 and 2009 
+36 
+Consolidated
+Statements of Income for the years ended March 31, 2010, 2009 and 2008 
+37 
+Consolidated Statements of
+Stockholders’ Equity and Comprehensive Income for the years ended March 31,
+2010, 2009 and 2008 
+38 
+Consolidated
+Statements of Cash Flows for the years ended March 31, 2010, 2009 and
+2008 
+39 
+Notes
+to Consolidated Financial Statements 
+40 
+34 
+Table
+of Contents 
+Report
+of Independent Registered Public Accounting Firm 
+To
+the Board of Directors and Stockholders 
+Iteris, Inc. 
+We
+have audited the accompanying consolidated balance sheets of Iteris, Inc. and
+subsidiary as of March 31, 2010 and 2009, and the related consolidated
+statements of income, stockholders’ equity and comprehensive income, and cash
+flows for each of the three years in the period ended March 31, 2010. These financial statements are the
+responsibility of the Company’s management. 
+Our responsibility is to express an opinion on these financial
+statements based on our audits. 
+We
+conducted our audits in accordance with the standards of the Public Company
+Accounting Oversight Board (United States). 
+Those standards require that we plan and perform the audit to obtain
+reasonable assurance about whether the financial statements are free of
+material misstatement. An audit includes
+examining, on a test basis, evidence supporting the amounts and disclosures in
+the financial statements. An audit also
+includes assessing the accounting principles used and significant estimates
+made by management, as well as evaluating the overall financial statement
+presentation. We believe that our audits
+provide a reasonable basis for our opinion. 
+As
+discussed in Note 8 to the consolidated financial statements, effective April 1,
+2009 the Company changed its method of accounting for certain common stock
+warrants. 
+In
+our opinion, the consolidated financial statements referred to above present
+fairly, in all material respects, the financial position of Iteris, Inc. and
+subsidiary as of March 31, 2010 and 2009, and the results of their
+operations and their cash flows for each of the three years in the period ended
+March 31, 2010, in conformity with U.S. generally accepted accounting
+principles. 
+We
+were not engaged to examine the effectiveness of Iteris, Inc.’s internal
+control over financial reporting as of March 31, 2010, and, accordingly,
+we do not express an opinion thereon. 
+/s/
+McGladrey & Pullen, LLP 
+Irvine,
+California 
+May 20,
+2010 
+35 
+Table of Contents 
+Iteris, Inc. 
+Consolidated Balance Sheets 
+(In thousands, except par value) 
+March 31, 
+2010 
+2009 
+Assets 
+Current
+assets: 
+Cash
+and cash equivalents 
+$ 
+10,405 
+$ 
+6,372 
+Trade
+accounts receivable, net of allowance for doubtful accounts of $768 and $534
+at March 31, 2010 and 2009, respectively 
+11,311 
+12,448 
+Costs
+in excess of billings on uncompleted contracts 
+3,871 
+4,217 
+Inventories 
+2,727 
+5,681 
+Deferred
+income taxes 
+4,993 
+4,241 
+Prepaid
+expenses and other current assets 
+623 
+272 
+Total
+current assets 
+33,930 
+33,231 
+Property
+and equipment, net 
+2,550 
+3,244 
+Deferred
+income taxes 
+9,739 
+11,505 
+Intangible
+assets, net 
+452 
+110 
+Goodwill 
+27,791 
+27,774 
+Other
+assets 
+200 
+202 
+Total
+assets 
+$ 
+74,662 
+$ 
+76,066 
+Liabilities and stockholders’ equity 
+Current
+liabilities: 
+Trade
+accounts payable 
+$ 
+2,492 
+$ 
+4,228 
+Accrued
+payroll and related expenses 
+2,709 
+3,188 
+Accrued
+liabilities 
+1,748 
+1,662 
+Billings
+in excess of costs and estimated earnings on uncompleted contracts 
+2,105 
+1,534 
+Current
+portion of long-term debt 
+2,324 
+2,019 
+Total
+current liabilities 
+11,378 
+12,631 
+Deferred
+rent 
+1,386 
+1,686 
+Unrecognized
+tax benefits 
+751 
+1,117 
+Other
+non-current liabilities 
+112 
+— 
+Long-term
+debt 
+2,969 
+5,274 
+Total
+liabilities 
+16,596 
+20,708 
+Commitments
+and contingencies 
+Stockholders’
+equity: 
+Preferred
+stock, $1.00 par value: 
+Authorized
+shares - 2,000 
+Issued
+and outstanding shares - none 
+— 
+— 
+Common
+stock. $0.10 par value: 
+Authorized
+shares - 70,000 at March 31, 2010 and 2009 
+Issued
+and outstanding shares - 34,318 at March 31, 2010 and 34,205 at
+March 31, 2009 
+3,432 
+3,420 
+Additional
+paid-in capital 
+137,503 
+136,997 
+Common
+stock held in trust 
+— 
+(31 
+) 
+Accumulated
+deficit 
+(82,869 
+) 
+(85,025 
+) 
+Accumulated
+other comprehensive loss 
+— 
+(3 
+) 
+Total
+stockholders’ equity 
+58,066 
+55,358 
+Total
+liabilities and stockholders’ equity 
+$ 
+74,662 
+$ 
+76,066 
+See accompanying notes. 
+36 
+Table of
+Contents 
+Iteris, Inc. 
+Consolidated Statements of Income 
+(In thousands, except
+per share amounts) 
+Year Ended March 31, 
+2010 
+2009 
+2008 
+Net
+sales and contract revenues: 
+Net
+sales 
+$ 
+31,650 
+$ 
+38,427 
+$ 
+40,326 
+Contract
+revenues 
+26,413 
+30,932 
+24,837 
+Total
+net sales and contract revenues 
+58,063 
+69,359 
+65,163 
+Costs
+of net sales and contract revenues: 
+Cost
+of net sales 
+16,505 
+20,346 
+20,499 
+Cost
+of contract revenues 
+17,399 
+21,094 
+16,367 
+Gross
+profit 
+24,159 
+27,919 
+28,297 
+Operating
+expenses: 
+Selling,
+general and administrative 
+17,004 
+18,035 
+17,289 
+Research
+and development 
+3,678 
+4,030 
+3,566 
+Amortization
+of intangible assets 
+159 
+147 
+147 
+Total
+operating expenses 
+20,841 
+22,212 
+21,002 
+Operating
+income 
+3,318 
+5,707 
+7,295 
+Non-operating
+income (expense): 
+Other
+income, net 
+44 
+116 
+252 
+Interest
+expense, net 
+(264 
+) 
+(646 
+) 
+(1,284 
+) 
+Income
+before income taxes 
+3,098 
+5,177 
+6,263 
+Benefit
+(provision) for income taxes 
+(895 
+) 
+5,297 
+5,900 
+Net
+income 
+$ 
+2,203 
+$ 
+10,474 
+$ 
+12,163 
+Earnings
+per share: 
+Basic 
+$ 
+0.06 
+$ 
+0.31 
+$ 
+0.37 
+Diluted 
+$ 
+0.06 
+$ 
+0.30 
+$ 
+0.35 
+Weighted-average
+shares outstanding: 
+Basic 
+34,249 
+33,964 
+32,723 
+Diluted 
+34,435 
+34,638 
+34,713 
+See accompanying
+notes. 
+37 
+Table of Contents 
+Iteris, Inc. 
+Consolidated Statements of Stockholders’ Equity and Comprehensive
+Income 
+(In thousands) 
+Common 
+Stock Shares 
+Amount 
+Additional 
+Paid-In 
+Capital 
+Common 
+Stock Held 
+in Trust 
+Notes 
+Receivable 
+From 
+Employees 
+Accumulated 
+Deficit 
+Accumulated
+Other 
+Comprehensive 
+Income (Loss) 
+Total
+Stockholder’s 
+Equity 
+Balance
+at March 31, 2007 
+30,601 
+$ 
+3,060 
+$ 
+130,425 
+$ 
+(374 
+) 
+$ 
+(5 
+) 
+$ 
+(107,438 
+) 
+$ 
+19 
+$ 
+25,687 
+Cumulative
+effect of adoption of new accounting for income taxes 
+— 
+— 
+— 
+— 
+— 
+(224 
+) 
+— 
+(224 
+) 
+Conversion
+of redeemable common stock to common stock 
+1,219 
+122 
+3,292 
+— 
+— 
+— 
+— 
+3,414 
+Warrant
+exercises 
+85 
+9 
+113 
+— 
+— 
+— 
+— 
+122 
+Stock
+option exercises 
+1,515 
+151 
+1,223 
+— 
+— 
+— 
+— 
+1,374 
+Stock-based
+compensation 
+— 
+— 
+290 
+— 
+— 
+— 
+— 
+290 
+Issuance
+of shares held in trust 
+— 
+— 
+178 
+172 
+— 
+— 
+— 
+350 
+Write-off
+of notes receivable from employees 
+— 
+— 
+(5 
+) 
+— 
+5 
+— 
+— 
+— 
+Components
+of comprehensive income: Foreign
+currency translation 
+— 
+— 
+— 
+— 
+— 
+— 
+35 
+35 
+Net
+income 
+— 
+— 
+— 
+— 
+— 
+12,163 
+— 
+12,163 
+Comprehensive
+income 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+12,198 
+Balance
+at March 31, 2008 
+33,420 
+3,342 
+135,516 
+(202 
+) 
+— 
+(95,499 
+) 
+54 
+43,211 
+Stock
+option exercises 
+785 
+78 
+861 
+— 
+— 
+— 
+— 
+939 
+Stock-based
+compensation 
+— 
+— 
+364 
+— 
+— 
+— 
+— 
+364 
+Issuance
+of shares held in trust 
+— 
+— 
+256 
+171 
+— 
+— 
+— 
+427 
+Components
+of comprehensive income: 
+Foreign
+currency translation 
+— 
+— 
+— 
+— 
+— 
+— 
+(57 
+) 
+(57 
+) 
+Net
+income 
+— 
+— 
+— 
+— 
+— 
+10,474 
+— 
+10,474 
+Comprehensive
+income 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+10,417 
+Balance
+at March 31, 2009 
+34,205 
+3,420 
+136,997 
+(31 
+) 
+— 
+(85,025 
+) 
+(3 
+) 
+55,358 
+Cumulative
+effect of adoption of change in accounting for warrants 
+— 
+— 
+— 
+— 
+— 
+(47 
+) 
+— 
+(47 
+) 
+Stock
+option exercises 
+113 
+12 
+131 
+— 
+— 
+— 
+— 
+143 
+Stock-based
+compensation 
+— 
+— 
+375 
+— 
+— 
+— 
+— 
+375 
+Issuance
+of shares held in trust 
+— 
+— 
+— 
+31 
+— 
+— 
+— 
+31 
+Components
+of comprehensive income: 
+Foreign
+currency translation 
+— 
+— 
+— 
+— 
+— 
+— 
+3 
+3 
+Net
+income 
+— 
+— 
+— 
+— 
+— 
+2,203 
+— 
+2,203 
+Comprehensive
+income 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+2,206 
+Balance
+at March 31, 2010 
+34,318 
+$ 
+3,432 
+$ 
+137,503 
+$ 
+— 
+$ 
+— 
+$ 
+(82,869 
+) 
+$ 
+— 
+$ 
+58,066 
+See accompanying
+notes. 
+38 
+Table of
+Contents 
+Iteris, Inc. 
+Consolidated Statements of Cash Flows 
+(In thousands) 
+Year Ended March 31, 
+2010 
+2009 
+2008 
+Cash flows from operating activities 
+Net
+income 
+$ 
+2,203 
+$ 
+10,474 
+$ 
+12,163 
+Adjustments
+to reconcile net income to net cash provided by operating activities: 
+Change
+in deferred tax assets 
+1,014 
+(5,398 
+) 
+(7,321 
+) 
+Depreciation
+of property and equipment 
+986 
+1,018 
+756 
+Stock-based
+compensation 
+375 
+364 
+290 
+Amortization
+of intangible assets 
+159 
+147 
+147 
+Gain
+on early extinguishment of debt 
+— 
+(50 
+) 
+(224 
+) 
+Amortization
+of debt discounts 
+— 
+109 
+201 
+Amortization
+of deferred financing costs 
+— 
+72 
+135 
+Amortization
+of deferred gain on sale-leaseback 
+— 
+— 
+(165 
+) 
+Changes
+in operating assets and liabilities: 
+Accounts
+receivable 
+1,137 
+660 
+(1,615 
+) 
+Net
+costs and estimated earnings in excess of billings 
+917 
+1,542 
+(1,383 
+) 
+Inventories 
+2,954 
+(1,455 
+) 
+2,153 
+Prepaid
+expenses and other assets 
+(350 
+) 
+97 
+(77 
+) 
+Accounts
+payable and accrued expenses 
+(2,911 
+) 
+(1,190 
+) 
+2,519 
+Net
+cash provided by operating activities 
+6,484 
+6,390 
+7,579 
+Cash flows from investing activities 
+Purchases
+of property and equipment 
+(294 
+) 
+(795 
+) 
+(739 
+) 
+Cash
+paid for business combination 
+(300 
+) 
+— 
+— 
+Net
+cash used in investing activities 
+(594 
+) 
+(795 
+) 
+(739 
+) 
+Cash flows from financing activities 
+Payments
+on borrowings on lines of credit, net 
+— 
+— 
+(4,015 
+) 
+Borrowings
+on long-term debt 
+750 
+6,543 
+— 
+Payments
+on long-term debt 
+(2,750 
+) 
+(7,069 
+) 
+(3,838 
+) 
+Proceeds
+from stock option exercises 
+143 
+939 
+1,374 
+Proceeds
+from warrant exercises 
+— 
+— 
+122 
+Credit
+facility commitment fees 
+— 
+— 
+(50 
+) 
+Checks
+drawn in excess of available bank balances 
+— 
+— 
+(47 
+) 
+Net
+cash provided by (used in) financing activities 
+(1,857 
+) 
+413 
+(6,454 
+) 
+Effect
+of exchange rate changes on cash 
+— 
+(57 
+) 
+— 
+Increase
+in cash and cash equivalents 
+4,033 
+5,951 
+386 
+Cash
+and cash equivalents at beginning of year 
+6,372 
+421 
+35 
+Cash
+and cash equivalents at end of year 
+$ 
+10,405 
+$ 
+6,372 
+$ 
+421 
+Supplemental cash flow information: 
+Cash
+paid during the year for: 
+Interest 
+$ 
+306 
+$ 
+545 
+$ 
+1,008 
+Income
+taxes 
+159 
+462 
+24 
+Supplemental schedule of non-cash investing and financing
+activities: 
+Liabilities
+incurred for business combination 
+$ 
+218 
+$ 
+— 
+$ 
+— 
+Fair
+value of common stock issued in settlement of liabilities 
+31 
+427 
+350 
+Conversion
+of redeemable common stock to common stock 
+— 
+— 
+3,414 
+Lease
+incentives in connection with new headquarters lease 
+— 
+— 
+1,772 
+Write-off
+of notes receivable from employees 
+— 
+— 
+(5 
+) 
+See accompanying
+notes. 
+39 
+Table
+of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements 
+March 31, 2010 
+1. Description
+of Business and Summary of Significant Accounting Policies 
+Description of Business 
+Iteris, Inc.
+(including our subsidiary, referred to collectively in these consolidated
+financial statements as “Iteris,” “the Company,” “we,” “our” and “us”) is a leader in the traffic management market
+focused on the development and application of advanced technologies that reduce
+traffic congestion, minimize the environmental impact of traffic congestion and
+improve the safety of surface transportation systems infrastructure. By
+combining outdoor image processing, traffic engineering and information
+technology, we offer a broad range of Intelligent Transportation Systems (“ITS”)
+and driver safety solutions to customers worldwide. Iteris was originally incorporated in
+Delaware in 1987. 
+Basis of Presentation 
+Our
+consolidated financial statements include the accounts of Iteris and our
+subsidiary, Iteris Europe GmbH. All significant intercompany accounts and
+transactions have been eliminated in consolidation. 
+Use of Estimates 
+The preparation of consolidated financial statements in conformity with
+accounting principles generally accepted in the United States requires our
+management to make certain estimates and assumptions that affect the reported
+amounts of assets and liabilities and disclosures of contingent assets and
+liabilities at the date of the financial statements, and reported amounts of
+revenues and expenses during the reporting period. Actual results could differ
+from those estimates. Significant estimates made in the preparation of the
+consolidated financial statements include the allowance for doubtful accounts,
+projections of taxable income used to assess realizability of deferred tax
+assets, inventory and warranty reserves, costs to complete long-term contracts,
+indirect cost rates used in cost-plus contracts, contract reserves, the
+valuation of debt and equity instruments and estimates of future cash flows
+used to assess the recoverability of long-lived assets and the impairment of
+goodwill. 
+Reclassifications 
+Certain
+reclassifications have been made to the prior year financial statements to
+conform to the current year presentation. 
+Revenue Recognition 
+Product revenues and related costs of sales are recognized upon the
+transfer of title, which generally occurs upon shipment or, if required, upon
+acceptance by the customer, provided that we believe collectibility of the net
+sales amount is reasonably assured. Accordingly, at the date revenue is
+recognized, the significant uncertainties concerning the sale have been
+resolved. 
+Contract revenues are derived primarily from long-term contracts with
+governmental agencies. Contract revenues include costs incurred plus a portion
+of estimated fees or profits determined on the percentage of completion method
+of accounting based on the relationship of costs incurred to total estimated
+costs. Any anticipated losses on contracts are charged to earnings when
+identified. Changes in job performance and estimated profitability, including
+those arising from contract penalty provisions and final contract settlements,
+may result in revisions to costs and revenues and are recognized in the period
+in which the revisions are determined. Profit incentives are included in
+revenue when their realization is reasonably assured. Costs and estimated
+earnings in excess of billings at March 31, 2010 and 2009 include $635,000
+and $684,000, respectively, that were not billable as certain milestone
+objectives specified in the contracts had not been attained. Substantially all
+costs and estimated earnings in excess of billings at March 31, 2010 are
+expected to be billed and collected during the fiscal year ending March 31,
+2011. 
+We also derive
+revenue from the provision of specific non-recurring contract engineering
+services and royalties. Non-recurring contract engineering revenues are
+recognized in the period in which the related services are performed. Royalty
+revenues are recorded in the period in which the royalty is earned based on
+unit sales of certain of our products. Non-recurring contract engineering and
+royalty revenues are included in net sales in the accompanying consolidated
+statements of income and totaled $685,000, $1.3 million and $1.9 million for
+the fiscal years ending March 31, 2010, 2009 and 2008, respectively. 
+40 
+Table
+of Contents 
+Foreign Currency 
+We have determined that
+the functional currency of our subsidiary in Europe is the United States
+(“U.S.”) dollar. Local currency financial statements are remeasured into U.S.
+dollars at the exchange rate in effect as of the balance sheet date for
+monetary assets and liabilities and the historical exchange rate for
+nonmonetary assets and liabilities. Revenues and expenses are remeasured using
+the average exchange rate for the period, except items related to nonmonetary
+assets and liabilities, which are remeasured using historical exchange rates.
+Remeasurement gains and losses are reported in “other income, net” in the
+consolidated statements of income. 
+Concentration of Credit Risk 
+Financial instruments that potentially subject us to a concentration of
+credit risk consist principally of cash and cash equivalents and trade accounts
+receivable. 
+Cash and cash equivalents consist primarily of demand deposits and
+money market funds maintained with several financial institutions. Deposits
+held with banks may exceed the amount of insurance provided on such deposits.
+Generally, these deposits may be redeemed upon demand and are maintained with
+high credit quality financial institutions and therefore have minimal credit
+risk. 
+Our accounts receivable are primarily derived from revenues earned from
+customers located throughout North America and Europe. We generally do not
+require collateral or other security from customers. We maintain an allowance
+for doubtful accounts for potential credit losses, which losses have
+historically been within management’s expectations. 
+Fair Values of Financial Instruments 
+The
+fair value of cash and cash equivalents, receivables, accounts payable and
+accrued expenses approximate carrying value because of the short period of time
+to maturity. The fair value of line of credit agreements, long-term debt and
+convertible debentures approximate carrying value because the related effective
+rates of interest approximate current market rates available to us for debt
+with similar terms and similar remaining maturities. The estimated fair value
+of certain of our outstanding warrants is determined using Level 3 Inputs (see
+Note 7). 
+Cash and Cash Equivalents 
+Cash and cash equivalents consist of cash and short-term investments
+with initial maturities of ninety days or less. 
+Allowance for Doubtful Accounts 
+The collectability of our accounts receivable is evaluated through
+review of invoices outstanding greater than a certain period of time and
+ongoing credit evaluations of our customers’ financial condition. In cases
+where we are aware of circumstances that may impair a specific customer’s
+ability to meet its financial obligations subsequent to the original sale, we
+will record an allowance against amounts due, and thereby reduce the net
+recognized receivable to the amount we reasonably believe will be collected. We
+also maintain an allowance based on our historical collections experience. When
+we determine that collection is not likely, we write off accounts receivable
+against the allowance for doubtful accounts. 
+Costs in Excess of Billings on Uncompleted Contracts 
+Costs in excess of billings on uncompleted contracts in the
+accompanying consolidated balance sheets represent unbilled amounts earned and
+reimbursable under services sales arrangements. At any given period-end, a
+large portion of the balance in this account represents the accumulation of
+labor, materials and other costs that have not been billed due to timing,
+whereby the accumulation of each month’s costs are not administratively billed
+until the subsequent month. Also included are amounts that become billable
+according to contract terms, which usually consider the passage of time,
+achievement of milestones or completion of the project. Generally, such
+unbilled amounts will be billed and collected within the next twelve months. 
+Billings in Excess of Costs and Estimated Earnings on Uncompleted
+Contracts 
+Billings in excess of costs and estimated earnings on uncompleted
+contracts in the accompanying consolidated balance sheets is comprised of cash
+collected from customers and billings to customers on contracts in advance of
+work performed, advance payments negotiated as a contract condition, estimated
+losses on uncompleted contracts, project-related legal liabilities and other
+project-related reserves. The majority of the unearned amounts will be
+earned within the next twelve months. 
+We record provisions for estimated losses on uncompleted contracts in
+the period in which such losses become known. The cumulative effects of
+revisions to contract revenues and estimated completion costs are recorded in
+the accounting period in which the amounts become evident and can be reasonably
+estimated. These revisions can include such items as the effects of change
+orders and claims, warranty claims, liquidated damages or other contractual
+penalties, adjustments for audit findings on U.S. or other government contracts
+and contract closeout settlements. 
+41 
+Table
+of Contents 
+Inventories 
+Inventories
+are stated at the lower of cost or market. Cost is determined using the first-in,
+first-out method. 
+Property and Equipment 
+Property
+and equipment are recorded at cost and are depreciated using the straight-line
+method over the estimated useful life ranging from three to eight years.
+Leasehold improvements are depreciated over the term of the related lease or
+the estimated useful life of the improvement, whichever is shorter. 
+Goodwill and Long-Lived Assets 
+Goodwill
+is tested for impairment on an annual basis in our fourth fiscal quarter or
+more frequently if indicators of impairment exist. The performance of the test
+involves a two-step process. The first step of the impairment test involves
+comparing the fair value of our reporting units with each respective reporting
+unit’s carrying amount, including goodwill. We determine the fair value of
+reporting units using the income approach with a reconciliation of the total
+reporting unit fair value to our total market capitalization. If the carrying
+amount of a reporting unit exceeds the reporting unit’s fair value, the second
+step of the goodwill impairment test is performed to determine the amount of
+any impairment loss. The second step of the goodwill impairment test involves
+comparing the implied fair value of the reporting unit’s goodwill with the
+carrying amount of that goodwill and an impairment charge is recorded for any
+excess carrying amount over fair value. We performed annual impairment
+assessments of the carrying value of goodwill for each of the fiscal years
+ended March 31, 2010, 2009 and 2008. Based on these assessments, we determined
+that no impairment as of each of these dates was indicated as the estimated
+fair value of each of our reporting units exceeded its respective carrying
+value. We monitor the indicators for goodwill impairment testing between annual
+tests. Certain adverse business conditions impacting one or more reporting
+units would cause us to test goodwill for impairment on an interim basis. 
+We
+also evaluate long-lived assets for impairment which requires impairment
+evaluation on long-lived assets used in operations when indicators of
+impairment are present. Reviews are
+performed to determine whether the carrying value of assets is impaired, based
+on a comparison of undiscounted expected future cash flows to the carrying
+value of the related net assets. If this
+comparison indicates that there is impairment, the impaired asset is written
+down to fair value, which is typically calculated using discounted expected
+future cash flows and a discount rate based upon our weighted average cost of
+capital adjusted for risks associated with the related operations. Impairment is based on the excess of the
+carrying amount over the fair value of those assets. 
+Income Taxes 
+We utilize the liability
+method of accounting for income taxes, whereby deferred taxes are determined
+based on the temporary differences between the financial statement and tax
+bases of assets and liabilities using enacted tax rates. A valuation allowance
+is recorded when it is more likely than not that all or a portion of the
+deferred tax assets will not be realized. 
+We
+must review all of our tax positions and make a determination as to whether
+each position is more-likely-than-not to be sustained upon examination by
+taxing authorities. If a tax position meets the more-likely-than-not standard,
+then the related tax benefit is measured based on a cumulative probability
+analysis of the amount that is more-likely-than-not to be realized upon
+effective settlement or disposition of the underlying issue. 
+Stock-Based
+Compensation 
+We record stock-based compensation in the consolidated
+statements of income as an expense, based on the grant date fair values of our
+stock-based awards, whereby such fair values are amortized over the requisite
+service period. The fair value of our common stock option awards is estimated
+on the grant date using the Black-Scholes-Merton (“BSM”) option-pricing
+formula, which considers, among other factors, the expected life of the award
+and the expected volatility of our stock price. 
+Research and Development Expenditures 
+Research and development expenditures are charged to expense
+in the period incurred. 
+42 
+Table of Contents 
+Shipping and Handling Costs 
+Shipping and handling costs are included as cost of sales in the period
+during which the products ship. 
+Sales Taxes 
+Sales taxes are presented on a net basis (excluded from net sales and
+contract revenues) in the consolidated statements of income. 
+Advertising Expenses 
+Advertising costs are expensed in the period incurred and totaled
+$153,000, $202,000 and $172,000 in the fiscal years ended March 31, 2010,
+2009 and 2008, respectively. 
+Warranty 
+We generally
+provide a one to three year warranty from the original invoice date on all
+products, materials and workmanship. 
+Products sold to certain original equipment manufacturer customers
+sometimes carry longer warranties. Defective products will be either repaired
+or replaced, generally at our option, upon meeting certain criteria. We accrue
+a provision for the estimated costs that may be incurred for product warranties
+relating to a product as a component of cost of sales at the time revenue for
+that product is recognized. The accrued
+warranty provision is included within accrued expenses in the accompanying
+consolidated balance sheets. 
+Repair and Maintenance Costs 
+We incur repair and maintenance costs in the normal course of business.
+Should the activity result in a permanent improvement to one of our leased
+facilities, the cost is capitalized as a leasehold improvement and amortized
+over its useful life or the remainder of the lease period, whichever is
+shorter. Non-permanent repair and maintenance costs are charged to expense as
+incurred. 
+Recent Accounting Pronouncements 
+In
+October 2009, the Financial Accounting Standards Board (“FASB”) issued
+Accounting Standards Update (“ASU”) No. 2009-13, Multiple-Deliverable
+Revenue Arrangements (“ASU 2009-13”), which amends the existing
+multiple-element revenue arrangements guidance currently included in Accounting
+Standards Codification (“ASC”) 605-25, Revenue Recognition —
+Multiple Element Arrangements . ASU 2009-13 provides for two
+significant changes to the existing multiple-element revenue arrangements
+guidance. The first relates to the determination of when the individual
+deliverables included in a multiple-element arrangement may be treated as
+separate units of accounting. The second change modifies the manner in which
+the transaction consideration is allocated across the separately identified
+deliverables. We plan to adopt the amendments prescribed by ASU 2009-13 for our
+fiscal year beginning April 1, 2010. We do not expect that the adoption of
+this ASU will have a material impact on our consolidated financial statements. 
+In October 2009, the
+FASB issued ASU No. 2009-14, Certain Revenue
+Arrangements That Include Software Elements (“ASU 2009-14”), which
+amends and modifies the scope of ASC 985-605, Software —
+Revenue Recognition , such that many sales transactions of tangible
+products that include software and other related transactions will fall outside
+its scope. We plan to adopt the amendments prescribed by ASU 2009-14 for our
+fiscal year beginning April 1, 2010. We do not expect that the adoption of
+this ASU will have a material impact on our consolidated financial statements. 
+In
+January 2010, the FASB issued ASU No. 2010-06, Improving
+Disclosures about Fair Value Measurements (“ASU 2010-06”), which
+amends ASC Topic 820,
+Fair Value Measurements and Disclosures 
+(“ASC 820”) to require various additional disclosures regarding fair value
+measurements and also clarify certain existing disclosure requirements.
+Additional requirements include disclosing (i) the amounts of significant
+transfers between Level 1 and Level 2 of the fair value hierarchy, (ii) the
+reasons for any transfers in or out of Level 3 and (iii) information in
+the reconciliation of recurring Level 3 measurements about purchases, sales,
+issuances and settlements on a gross basis. ASU 2010-06 does not change any accounting
+requirements, but is expected to have a significant effect on the disclosures
+of entities that measure assets and liabilities at fair value. The amendments
+prescribed by ASU 2010-06 became effective for our fiscal quarter ending March 31,
+2010, except for the requirements described in item (iii) above, which
+will be effective for our fiscal year beginning April 1, 2011. The
+adoption of this ASU did not have a material impact on our consolidated
+financial statements. 
+43 
+Table of
+Contents 
+2. Supplementary Financial Information 
+Inventories 
+The following table presents details regarding our inventories: 
+March 31, 
+2010 
+2009 
+(In thousands) 
+Materials
+and supplies 
+$ 
+2,292 
+$ 
+4,820 
+Work
+in process 
+49 
+198 
+Finished
+goods 
+386 
+663 
+$ 
+2,727 
+$ 
+5,681 
+Property and Equipment 
+The following table
+presents details of our property and equipment: 
+March 31, 
+2010 
+2009 
+(In thousands) 
+Equipment 
+$ 
+8,334 
+$ 
+8,136 
+Leasehold
+improvements 
+1,940 
+1,930 
+Accumulated
+depreciation 
+(7,724 
+) 
+(6,822 
+) 
+$ 
+2,550 
+$ 
+3,244 
+Intangible Assets 
+The following table presents details regarding our
+intangible assets: 
+March 31, 2010 
+March 31, 2009 
+Gross 
+Carrying 
+Amount 
+Accumulated 
+Amortization 
+Gross 
+Carrying 
+Amount 
+Accumulated 
+Amortization 
+(In thousands) 
+Intangible
+assets subject to amortization: 
+Developed
+technology 
+$ 
+996 
+$ 
+(595 
+) 
+$ 
+495 
+$ 
+(482 
+) 
+Patents 
+317 
+(266 
+) 
+317 
+(220 
+) 
+Total 
+$ 
+1,313 
+$ 
+(861 
+) 
+$ 
+812 
+$ 
+(702 
+) 
+Amortization expense for
+intangible assets subject to amortization was $159,000, $147,000, and $147,000
+for the fiscal years ended March 31, 2010, 2009 and 2008, respectively.
+Future estimated amortization expense is as follows: 
+Year Ending March 31: 
+(In thousands) 
+2011 
+146 
+2012 
+106 
+2013 
+100 
+2014 
+100 
+$ 
+452 
+If
+we acquire additional intangible assets in future periods, our amortization
+expense will increase. 
+44 
+Table of Contents 
+Goodwill 
+The following table
+presents the activity related to the carrying value of our goodwill by reportable
+segment for the fiscal year ended March 31, 2010: 
+Roadway 
+Sensors 
+Vehicle 
+Sensors 
+Transportation 
+Systems 
+Total 
+(In thousands) 
+Beginning
+balance 
+$ 
+8,197 
+$ 
+4,671 
+$ 
+14,906 
+$ 
+27,774 
+Goodwill
+recorded in connection with Hamilton Signal acquisition (Note 3) 
+17 
+— 
+— 
+17 
+Ending
+balance 
+$ 
+8,214 
+$ 
+4,671 
+$ 
+14,906 
+$ 
+27,791 
+Warranty Reserve Activity 
+The following table presents activity with respect to the
+warranty reserve: 
+Year Ended March 31, 
+2010 
+2009 
+2008 
+(In thousands) 
+Balance
+at beginning of year 
+$ 
+582 
+$ 
+494 
+$ 
+520 
+Additions
+charged to cost of sales 
+221 
+342 
+347 
+Warranty
+claims 
+(335 
+) 
+(254 
+) 
+(373 
+) 
+Balance
+at end of year 
+$ 
+468 
+$ 
+582 
+$ 
+494 
+Earnings Per Share 
+The following table sets forth the computation of basic and diluted
+earnings per share: 
+Year Ended March 31, 
+2010 
+2009 
+2008 
+(In
+thousands, except per share amounts) 
+Numerator: 
+Net
+income 
+$ 
+2,203 
+$ 
+10,474 
+$ 
+12,163 
+Denominator: 
+Weighted
+average common shares used in basic computation 
+34,249 
+33,964 
+32,723 
+Dilutive
+stock options 
+185 
+671 
+1,973 
+Dilutive
+warrants 
+1 
+3 
+17 
+Weighted
+average common shares used in diluted computation 
+34,435 
+34,638 
+34,713 
+Earnings
+per share: 
+Basic 
+$ 
+0.06 
+$ 
+0.31 
+$ 
+0.37 
+Diluted 
+$ 
+0.06 
+$ 
+0.30 
+$ 
+0.35 
+The
+following instruments were excluded from the computation of diluted earnings
+per share as their effect would have been 
+anti-dilutive: 
+Year Ended March 31, 
+2010 
+2009 
+2008 
+(In thousands) 
+Stock
+options 
+1,790 
+1,518 
+520 
+Warrants 
+371 
+1,158 
+1,170 
+Convertible
+debentures 
+— 
+1,281 
+2,661 
+45 
+Table of Contents 
+3. Business Combination 
+On
+April 3, 2009 (the “Closing”), we completed the acquisition of certain
+assets of Hamilton Signal, Inc., a privately-held developer of video
+processing algorithms enabling state and local governments to conduct real-time
+analysis on fixed and pan-tilt-zoom camera feeds. The total purchase
+consideration was approximately $518,000, for which we paid $300,000 in cash
+upon execution of the purchase agreement, and for which, pursuant to the
+purchase agreement, we paid an additional $106,000 on the first
+anniversary of the Closing and are required to pay approximately $112,000
+on the second anniversary of the Closing. Pursuant to the purchase agreement,
+the seller became an employee of Iteris and is eligible to receive compensation
+based on future net sales of certain products during the three-year period
+ending March 31, 2012, subject to continued employment and other
+limitations. 
+We
+have accounted for this acquisition as a business combination. We estimated the
+fair value of the assets acquired to allocate the purchase price, which is
+summarized as follows (in thousands): 
+Developed
+technology 
+$ 
+501 
+Goodwill 
+17 
+$ 
+518 
+The
+purchased developed technology was determined to have an estimated useful life
+of five years. Our primary reasons for the acquisition were to expand our
+product portfolio in the traffic management market and to incorporate enhanced
+functionality into and complement our Roadway Sensors technologies. 
+Our
+consolidated financial statements for the fiscal year ended March 31, 2010
+include the results of operations of Hamilton Signal commencing as of the
+Closing. Disclosures required for material business combinations have been
+limited due to the immateriality of the acquisition of Hamilton Signal to our
+consolidated financial statements. No supplemental pro forma information is
+presented for the acquisition due to the immaterial effect of the acquisition
+on our results of operations. 
+4. Revolving Line of Credit and
+Long-Term Debt 
+Revolving Line of Credit 
+Prior to October 16, 2008, we had a credit
+facility with a bank that provided for line of credit borrowings of up to $10.0
+million. Under this credit facility, we could borrow against our eligible
+accounts receivable and eligible inventory, as defined in the credit agreement.
+Interest on borrowed amounts under the line of credit was payable monthly at
+the current stated prime rate plus 1.00%. Additionally, we were obligated to
+pay an unused line fee of 0.25% per annum applied to the amount by which the
+maximum credit amount exceeded the average daily principal balance during the
+preceding month. The credit facility required $2,000 in monthly collateral
+management fees and included an early termination fee equal to 2% of the total
+facility during the first year of the agreement and 1% of the total facility in
+the second year of the agreement. This credit facility was secured by
+substantially all of our assets and expired on October 15, 2008. 
+Effective October 16,
+2008, we entered into a new $19.5 million credit facility with a different
+bank, which replaced the credit facility discussed above. This new credit
+facility provides for a two-year revolving line of credit with borrowings of up
+to $12.0 million and a $7.5 million 48-month term note (discussed below).
+Interest on borrowed amounts under the revolving line of credit are payable
+monthly at a rate equal to the current stated prime rate (3.25% at March 31,
+2010) up to the current stated prime rate plus 0.50%, depending on aggregate
+deposit balances maintained at the bank in relation to the total loan
+commitment under the credit facility. We are obligated to pay an unused line
+fee of 0.25% per annum applied to the average unused portion of the revolving
+line of credit during the preceding month. The revolving line of credit does
+not contain any early termination fees and is secured by substantially all of
+our assets. As of March 31, 2010, no amounts were borrowed under the
+revolving line of credit portion of the facility. Availability under this line
+of credit may be reduced or otherwise limited as a result of our obligations to
+comply with certain financial covenants. 
+46 
+Table of Contents 
+Long-Term Debt 
+Our long-term debt consists of the following: 
+March 31, 
+2010 
+2009 
+(In thousands) 
+Bank
+term note 
+$ 
+5,293 
+$ 
+6,543 
+Convertible
+debentures, net 
+— 
+750 
+5,293 
+7,293 
+Less
+current portion 
+(2,324 
+) 
+(2,019 
+) 
+$ 
+2,969 
+$ 
+5,274 
+Convertible
+Debentures, Net. In
+May 2004, we sold and issued subordinated convertible debentures in the
+aggregate original principal amount of $10.1 million. In connection with the
+issuance of the debentures, we issued warrants to purchase an aggregate of
+639,847 shares of our common stock, the value of which was recorded as a debt
+discount against the face amount of the debentures on the date of issuance and
+has been amortized to interest expense over the term of the convertible
+debentures. 
+The debentures
+were due in full on May 19, 2009, provided for 6.0% annual interest,
+payable quarterly, and were convertible into our common stock at an initial
+conversion price of $3.61 per share, subject to certain adjustments, including
+adjustments for dilutive issuances. From May 19, 2008 until the maturity
+date, we were permitted to redeem the debentures at 110% of the principal
+amount. During the period that the debentures were outstanding, $250,000 of
+debentures had been converted into 69,252 shares of our common stock. 
+During the fiscal
+year ended March 31, 2008, at the holders’ request, we paid $1.8 million
+in cash to retire $2.1 million of convertible debentures early, for which we
+recorded a net gain of $224,000. During the fiscal year ended March 31,
+2009, we early-retired an additional $7.0 million of outstanding convertible
+debentures, also at the holders’ request, for a net gain of approximately
+$50,000. For this retirement we used $300,000 of our cash and financed $6.5
+million under our bank term note, which is described below under the caption “Bank
+Term Notes.” The net gains above were recorded within “other income, net” for
+their respective fiscal years within the accompanying consolidated statements
+of income. 
+In May 2009,
+we retired the remaining $750,000 of convertible debentures. The retirement was
+financed under our bank term note. 
+Bank Term
+Notes. In October 2004,
+we entered into a $5.0 million term note payable with a bank. The note was due
+on May 27, 2008, and provided for monthly principal payments of
+approximately $104,000. The final
+payment against this term note was made in June 2008. 
+Effective October 16,
+2008, we entered into a new $19.5 million credit facility with a different
+bank, as described above. Under this
+credit facility, we may borrow up to $7.5 million in the form of a 48-month
+term note. As of March 31, 2010, we had outstanding borrowings of
+approximately $5.3 million under the term note. Principal payments under this
+term note are required to be repaid in 48 monthly installments of $152,000
+commencing on June 1, 2009. Additionally, beginning on November 1,
+2009, and on November 1 of each year thereafter, we are required to repay
+additional principal of up to $500,000, calculated based on certain financial
+measures, as further defined in the agreement. These additional principal
+payments effectively reduce the total number of monthly installments necessary
+to repay the term note. As of March 31, 2010, an additional $500,000 was
+included in the current portion of the term note, representing the amount we
+estimate will be due on November 1, 2010. Interest on the term note is
+payable monthly at a rate equal to the current stated prime rate plus 0.50% up
+to the current stated prime rate plus 1.00%, depending on aggregate deposit
+balances maintained at the bank in relation to the total loan commitment under
+the credit facility. The term note contains no early termination fees and,
+along with the revolving line of credit under the same credit agreement, is
+secured by substantially all of our assets. 
+47 
+Table
+of Contents 
+Scheduled aggregate maturities of long-term debt principal as of March 31,
+2010 were as follows: 
+Year Ending March 31: 
+(In thousands) 
+2011 
+$ 
+2,324 
+2012 
+2,324 
+2013 
+645 
+$ 
+5,293 
+5. Income Taxes 
+For financial reporting purposes, income before income taxes includes
+the following components: 
+Year Ended March 31, 
+2010 
+2009 
+2008 
+(In thousands) 
+United
+States 
+$ 
+3,177 
+$ 
+4,927 
+$ 
+6,119 
+Foreign 
+(79 
+) 
+250 
+144 
+$ 
+3,098 
+$ 
+5,177 
+$ 
+6,263 
+The reconciliation of our income tax provision (benefit) to taxes
+computed at U.S. federal statutory rates is as follows: 
+Year Ended March 31, 
+2010 
+2009 
+2008 
+(In thousands) 
+Income
+tax provision at statutory rates 
+$ 
+1,053 
+$ 
+1,761 
+$ 
+2,131 
+State
+income taxes net of federal benefit 
+183 
+57 
+(675 
+) 
+Change
+in valuation allowance associated with federal deferred tax assets 
+— 
+(6,915 
+) 
+(7,558 
+) 
+Compensation
+charges 
+(12 
+) 
+(4 
+) 
+194 
+Unrecognized
+tax benefits 
+(362 
+) 
+(290 
+) 
+(133 
+) 
+Other 
+33 
+94 
+141 
+Provision
+(benefit) for income taxes 
+$ 
+895 
+$ 
+(5,297 
+) 
+$ 
+(5,900 
+) 
+The components of deferred tax assets and liabilities are as follows: 
+March 31, 
+2010 
+2009 
+(In thousands) 
+Deferred
+tax assets: 
+Net
+operating losses 
+$ 
+13,273 
+$ 
+13,942 
+Credit
+carry forwards 
+272 
+247 
+Deferred
+compensation and payroll 
+691 
+1,035 
+Bad
+debt allowance and other reserves 
+796 
+672 
+Property
+and equipment 
+42 
+— 
+Other,
+net 
+167 
+295 
+Total
+deferred tax assets 
+15,241 
+16,191 
+Deferred
+tax liabilities: 
+Property
+and equipment 
+— 
+(104 
+) 
+Acquired
+intangibles 
+(509 
+) 
+(341 
+) 
+Total
+deferred tax liabilities 
+(509 
+) 
+(445 
+) 
+Net
+deferred tax assets 
+$ 
+14,732 
+$ 
+15,746 
+48 
+Table of
+Contents 
+The components of current and deferred federal and
+state income tax provisions and (benefits) are as follows: 
+Year Ended March 31, 
+2010 
+2009 
+2008 
+(In thousands) 
+Current
+income tax provision (benefit): 
+Federal 
+$ 
+(234 
+) 
+$ 
+(200 
+) 
+$ 
+94 
+State 
+126 
+223 
+40 
+Foreign 
+(11 
+) 
+78 
+40 
+Deferred
+income tax provision (benefit): 
+Federal 
+862 
+(5,261 
+) 
+(5,011 
+) 
+State 
+152 
+(137 
+) 
+(1,063 
+) 
+Net
+income tax provision (benefit) 
+$ 
+895 
+$ 
+(5,297 
+) 
+$ 
+(5,900 
+) 
+At March 31, 2010, we had approximately $260,000 in federal
+alternative minimum tax credit carryforwards and $30,000 in state alternative
+minimum tax credit carryforwards that can be carried forward indefinitely. We
+had $38.5 million of federal net operating loss carryforwards at March 31,
+2010 that begin to expire in 2019. We also had $18.5 million of state net
+operating loss carryforwards at March 31, 2010, of which, $10.2 million
+are scheduled to expire in 2013, $7.9 million are scheduled to expire in 2014
+and $400,000 are scheduled to expire in 2016. 
+In May 2004, we acquired a greater than 80% ownership interest in
+a former subsidiary and, from that date forward our income taxes are provided
+on a consolidated basis for federal income tax purposes. Due to changes in
+stock ownership, our federal net operating loss carryforwards of approximately
+$38.5 million and other federal attributes are subject to a Section 382
+annual limitation. 
+Our deferred tax assets at March 31, 2010 do not include $2.4
+million of excess tax benefits from employee stock option exercises that are a
+component of our net operating loss carryforwards. If and when such excess tax benefits
+are realized, stockholders’ equity will be adjusted. 
+At March 31, 2010, we determined that it is more likely than not
+that our deferred tax assets will be realized. In making such determination, we
+reviewed all available positive and negative evidence, including reversal of
+deferred tax liabilities, potential carrybacks, projected future taxable
+income, tax planning strategies and recent financial performance. 
+Unremitted earnings of our foreign subsidiary have been included in the
+consolidated financial statements without giving effect to the U.S. taxes that
+may be payable on distribution to the U.S. because it is not anticipated that
+such earnings will be remitted to the U.S. If remitted, the additional U.S.
+taxes would not be material. 
+Unrecognized Tax Benefits 
+As
+of April 1, 2007, we recognized the cumulative impact of our adoption of
+new accounting guidance for uncertainty in income taxes as a $224,000 increase
+to our liability for unrecognized tax benefits with a corresponding increase to
+our accumulated deficit. As of March 31, 2010 and 2009, our gross
+unrecognized tax benefits were $2.1 million and $2.5 million, respectively, of
+which $1.7 million and $2.0 million, respectively, if recognized, would affect
+our effective tax rate. 
+Our
+continuing practice is to recognize interest and/or penalties related to income
+tax matters in income tax expense. As of March 31, 2010 and 2009, we had
+accrued cumulatively $40,000 and $39,000, respectively, for the payment of
+potential interest and penalties. 
+49 
+Table of
+Contents 
+A
+reconciliation of the beginning and ending balances of the total amounts of
+gross unrecognized tax benefits is as follows (in thousands): 
+Increases
+in tax positions for prior year 
+1,160 
+Decreases
+in tax positions for prior year 
+(147 
+) 
+Increases
+in tax positions for current year 
+327 
+Lapse
+in statute of limitations 
+(136 
+) 
+Gross
+unrecognized tax benefits at March 31, 2008 
+2,788 
+Increases
+in tax positions for prior year 
+155 
+Decreases
+in tax positions for prior year 
+(36 
+) 
+Increases
+in tax positions for current year 
+22 
+Lapse
+in statute of limitations 
+(404 
+) 
+Gross
+unrecognized tax benefits at March 31, 2009 
+2,525 
+Increases
+in tax positions for prior year 
+93 
+Decreases
+in tax positions for current year 
+(51 
+) 
+Lapse
+in statute of limitations 
+(414 
+) 
+Gross
+unrecognized tax benefits at March 31, 2010 
+$ 
+2,153 
+We
+anticipate a decrease in gross unrecognized tax benefits of approximately
+$330,000 within the next twelve months based on federal and state statute
+expirations in various jurisdictions. 
+We
+are subject to taxation in the U.S. and various states. We are subject to U.S.
+federal tax examination for fiscal tax years ended March 31, 2007 or
+later, and state and local income tax examination for fiscal tax years ended March 31,
+2006 or later. 
+6. Commitments
+and Contingencies 
+Litigation and Other
+Contingencies 
+From time to time, we have
+been involved in litigation relating to claims arising out of our operations in
+the normal course of business. We currently are not a party to any legal
+proceedings, the adverse outcome of which, in management’s opinion,
+individually or in the aggregate, would have a material adverse effect on our
+consolidated results of operations, financial position or cash flows. 
+Furthermore, from time to time, we have experienced
+unforeseen developments in contingencies related to our former subsidiaries.
+For example, we have been the subject of a number of routine tax audits for
+time periods and jurisdictions related to the businesses of our former
+subsidiaries. Although the development and ultimate outcome of these types of
+unforeseen matters cannot be anticipated or predicted with any certainty, our
+management does not believe that we are presently involved in any matters
+related to our former subsidiaries that would have a material adverse effect on
+our consolidated results of operations, financial position or cash flows. 
+Operating Leases 
+In May 2007, we
+entered into an agreement to lease 52,000 square feet of office space in Santa
+Ana, California for a term of 88 months. In September 2007, we relocated
+our headquarters and principal operations into this space. The monthly lease
+rate was $102,000 during the first year of the lease and increases each year
+thereafter, up to a maximum of $120,000 during the last year of the lease. The
+lease may be extended for a period of five years, at our option, at a lease
+rate to be based on the market lease rate for comparable property determined as
+of the commencement date of the extension period. Additionally, the lease
+agreement provided for $1.8 million in incentives in the form of tenant
+improvement allowances, which we recorded as deferred rent and capitalized
+leasehold improvements in our consolidated balance sheet. The deferred rent
+amount reduces monthly rent expense over the term of the lease, and the
+capitalized leasehold improvements amount are being depreciated over the initial
+term of the lease (the estimated useful life of the related leasehold
+improvements). 
+50 
+Table of Contents 
+We have lease commitments for facilities in various locations
+throughout the U.S. as well as certain other equipment. Future minimum rental
+payments under these noncancelable operating leases at March 31, 2010 were
+as follows: 
+Year Ending March 31: 
+(In thousands) 
+2011 
+$ 
+1,837 
+2012 
+1,529 
+2013 
+1,418 
+2014 
+1,416 
+2015 
+1,064 
+$ 
+7,264 
+Rent expense totaled $1.9 million, $1.8 million and $2.1 million for
+the fiscal years ended March 31, 2010, 2009 and 2008, respectively. 
+We previously recorded on our consolidated balance sheet a deferred
+gain related to the May 2002 sale and leaseback of our prior headquarters
+in Anaheim, California. The deferred gain was amortized over the term of the
+underlying lease, which terminated in September 2007. For the fiscal year
+ended March 31, 2008, we recorded a realized gain of $165,000 pertaining
+to this deferred gain which was recorded as a reduction to rent expense. 
+Related Party Transaction 
+We previously
+subleased office space to MAXxess Systems, Inc. (“MAXxess”), one of our
+former subsidiaries that we sold in September 2003 and is currently owned
+by an investor group that includes two of our directors, one of whom is the
+Chief Executive Officer of MAXxess. The sublease terminated in September 2007,
+at which time MAXxess owed us an aggregate of $274,000 related to this sublease
+and certain related ancillary services that we provided to MAXxess. We have
+previously fully reserved for amounts owed to us by MAXxess under the terms of
+this sublease. In August 2009, MAXxess executed a promissory note payable
+to Iteris for $274,000. The promissory note bears interest at a rate of 6% per
+annum, compounded annually, with accrued interest to be paid annually on the
+first business day of each calendar year. Payments under the note may be made
+in bona fide services rendered by MAXxess to Iteris to the extent such services
+and amounts are pre-approved in writing by us. All amounts outstanding under
+the note will become due and payable on the earliest of (i) August 10,
+2014, (ii) a change of control in MAXxess, or (iii) a financing by
+MAXxess resulting in gross proceeds of at least $10 million. As of March 31,
+2010, the entire $274,000 principal balance was outstanding and payable to
+Iteris and remains fully reserved. 
+Inventory Purchase Commitments 
+At March 31, 2010, we had firm commitments to purchase
+approximately $1.2 million of inventory, primarily during the first and second
+quarters of our fiscal year ending March 31, 2011. 
+Deferred Compensation Plan 
+In 1986, we
+adopted the Executive Deferral Plan (the “1986 Plan”) under which certain
+executives were able to defer a portion of their annual compensation into the
+1986 Plan. All deferred amounts earned interest, generally with no guaranteed
+rate of return. During the fiscal year
+ended March 31, 2003, we adopted the Deferred Compensation Plan, and all
+assets of the 1986 Plan were transferred into the Deferred Compensation Plan
+(the “Plan”). No compensation withholdings were deferred under the 1986 Plan or
+the Plan in the fiscal years ended March 31, 2010, 2009 and 2008. 
+Shares of our common stock that were held in the Plan were recorded as
+a liability in our consolidated balance sheets based on the quoted market price
+of our common stock at the close of each reporting period. Changes in the value
+of our common stock between reporting periods have been presented within
+operating expenses in the accompanying consolidated statements of income. As a
+result of such changes in the value of Iteris common stock, we recorded
+expenses of $72,000 and $21,000 in the fiscal years ended March 31, 2009
+and 2008, respectively. During the fiscal year ended March 31, 2009, we
+distributed from the plan to its owner, approximately 143,000 shares with a
+total fair market value at the distribution date of approximately $427,000. As
+of March 31, 2009, the Plan held 23,844 shares of our common stock. In December 2009,
+we distributed these remaining shares to their respective owners, which
+effectively terminated the Plan, along with the corresponding trust in which
+the assets were held. As of March 31, 2010, the original $31,000 cost
+basis of the 23,844 shares, which was previously recorded as a contra-equity
+account, along with the corresponding liability, were no longer recorded on our
+consolidated balance sheet. 
+51 
+Table of Contents 
+7. Fair
+Value Measurements 
+We measure fair value as the exchange price that would
+be received for an asset or paid to transfer a liability (an exit price) in the
+principal or most advantageous market for the asset or liability in an orderly
+transaction between market participants on the measurement date. Fair value
+measurements are based on a three-tier hierarchy that prioritizes the inputs
+used to measure fair value. These tiers include: Level 1, defined as observable
+inputs such as quoted prices in active markets for identical assets and
+liabilities; Level 2, defined as observable inputs other than Level 1 prices
+such as quoted prices for similar assets or liabilities or prices quoted in
+inactive markets; and Level 3, defined as unobservable inputs for which little
+or no market data exists, therefore requiring an entity to develop its own
+assumptions. 
+At March 31, 2010, there were outstanding
+warrants to purchase shares of our common stock that were classified as a
+liability with an estimated fair value of $27,000 (see Note 8). These warrants
+were valued using Level 3 inputs because there are unobservable inputs
+associated with them. The following table reconciles the liability for these
+warrants measured at fair value on a recurring basis using Level 3 inputs for
+the fiscal year ended March 31, 2010 (in thousands): 
+Balance
+at April 1, 2009 
+$ 
+— 
+Cumulative
+effect of accounting change (Note 8) 
+47 
+Gain
+on change in fair value included in net income 
+(20 
+) 
+Balance
+at March 31, 2010 
+$ 
+27 
+This
+liability is included within accrued liabilities in the accompanying
+consolidated balance sheet as of March 31, 2010. 
+The intangible assets acquired in connection with
+the Hamilton Signal acquisition (see Note 3) were recorded at fair value as of
+the acquisition date of such assets, and were estimated using the income
+approach, which included the use of Level 3 inputs. Our non-financial assets,
+such as goodwill, intangible assets and property and equipment, are measured at
+fair value on a non-recurring basis; generally when there is a transaction
+involving those assets such as a purchase transaction, a business combination
+or an adjustment for impairment. 
+8. Stockholders’
+Equity 
+Preferred Stock 
+Our certificate of incorporation provides for the issuance of up to
+2,000,000 shares of preferred stock. As of March 31, 2010 and 2009, there
+were no outstanding shares of preferred stock, and we do not currently have
+plans to issue any shares of preferred stock. 
+In August 2009, our Board of Directors adopted
+a stockholder rights plan, which calls for preferred stock purchase rights
+(each, a “Right”) to be distributed, as a dividend, at the rate of one Right
+for each share of common stock held as of September 3, 2009. Each Right
+will entitle holders of common stock to buy one one-thousandth of one share of Series A
+Junior Participating Preferred Stock of Iteris. A further description and terms
+of the Rights are set forth in the Rights Agreement dated August 20, 2009
+by and between Iteris and Computershare Trust Company, N.A., as rights agent.
+In connection with the stockholder rights plan, our Board of Directors approved
+the adoption of a Certificate of Designations, which created the Series A
+Junior Participating Preferred Stock, and likewise authorized the filing of a
+Certification of Elimination to eliminate the two series of junior
+participating preferred stock, which were originally created in April 1998
+in connection with our previous stockholder rights plan which expired in 2008. 
+Our Board of Directors is authorized to issue from time to time such
+authorized but unissued shares of preferred stock in one or more series and to
+fix or alter the designations, preferences, rights and any qualifications,
+limitations or restrictions of the shares of each such series, including the
+dividend, conversion, voting, redemption and liquidation rights. 
+52 
+Table of Contents 
+Common Stock Warrants 
+The following table summarizes information regarding outstanding
+warrants to purchase our common stock as of March 31, 2010: 
+Exercise Price 
+Warrants 
+Outstanding 
+Weighted Average 
+Remaining 
+Contractual Life 
+(In thousands) 
+(Years) 
+$ 
+1.42 
+15 
+3.4 
+$ 
+3.25 
+246 
+0.9 
+$ 
+5.00 
+75 
+0.3 
+336 
+0.9 
+All of the outstanding warrants were exercisable at March 31,
+2010. Upon the exercise of warrants, we issue new shares of common stock from
+our authorized shares. Warrants to purchase an aggregate of 246,260 shares
+of common stock at an exercise price of $3.25 per share are callable by us, for
+a purchase price of $0.01 per share, if the market price of our common stock
+trades for 20 consecutive days at a price equal to or greater than two times
+the exercise price of the warrants. Warrants to purchase an aggregate of
+75,000 shares of common stock at an exercise price of $5.00 per share are
+callable by us, for an aggregate purchase price of $1.00, if the market price
+of our common stock trades for 20 consecutive days at a price equal to or
+greater than one and a half times the exercise price of the warrants. In
+connection with the issuance of warrants to purchase an aggregate of 246,250
+shares of our common stock in September 2006, we are party to a
+registration rights agreement that contains provisions under which we could be
+subjected to liquidated damages should we fail to maintain effective
+registration statements for the shares of common stock issuable upon exercise
+of the warrants. As of March 31, 2010, no liquidated damages were payable
+under the provisions of the registration rights agreement associated with these
+warrants. 
+In May 2009,
+outstanding warrants with a weighted average per share exercise price of $3.93
+to purchase approximately 674,000 shares of our common stock, which were
+associated with our convertible debentures (see Note 4), expired unexercised.
+In July 2009, outstanding warrants with a per share exercise price of
+$5.26 to purchase approximately 155,000 shares of our common stock expired
+unexercised. 
+In connection with our adoption of certain
+provisions of accounting for derivatives, which became effective for us on April 1,
+2009, we determined that certain outstanding warrants to purchase shares of our
+common stock contain provisions that provide for a possible future adjustment
+to either the exercise price and/or number of shares to be issued upon exercise.
+As such, beginning April 1, 2009, we began recognizing these warrants as
+liabilities at their respective estimated fair values on each reporting date.
+The cumulative effect of the change in accounting for these warrants of $47,000
+was recognized as an adjustment to the opening balance of accumulated deficit
+at April 1, 2009. The amounts recognized in the consolidated balance sheet
+as a result of our adoption on April 1, 2009 were determined based on the
+amounts that would have been recognized if this accounting treatment had been
+applied from the issuance date of the warrants. At March 31, 2010, the
+estimated fair value of the warrants was $27,000. The change in the estimated
+fair value of the warrants for the fiscal year ended March 31, 2010 is
+included in “other income, net” in the accompanying consolidated statement of
+income. These warrants are scheduled to expire in February 2011. We
+estimate the fair value of these warrants using the BSM option-pricing formula. 
+Common Stock 
+The following summarizes common stock reserved for
+future issuance at March 31, 2010: 
+(In thousands) 
+Shares
+issuable under stock options plans (Note 9) 
+4,100 
+Shares
+issuable under the exercise of warrants 
+336 
+4,436 
+53 
+Table of
+Contents 
+9. Employee Benefit Plans 
+Stock Option Plans 
+In September 2007,
+our stockholders approved the 2007 Omnibus Incentive Plan (the “2007 Plan”),
+which provides that options to purchase shares of our unissued common stock may
+be granted to our employees, officers, consultants and directors at exercise
+prices which are equal to or greater than the market value of our common stock
+on the date of grant. Options expire no more than ten years after the date of
+grant and generally vest at the rate of 25% on each of the first four
+anniversaries of the grant date. The 2007 Plan also allows for the issuance of
+stock appreciation rights, restricted stock, restricted stock units and other
+stock-based awards based on the value of our common stock. New shares are
+issued to satisfy stock option exercises and share issuances under the 2007
+Plan. As of March 31, 2010, options to purchase approximately 768,000
+shares of common stock were outstanding under the 2007 Plan. 
+Our 1997 Stock
+Incentive Plan (the “1997 Plan”) terminated in September 2007; however,
+all stock options outstanding under the 1997 Plan remain outstanding pursuant
+to the terms of such stock options. As of March 31, 2010, options to
+purchase approximately 1.1 million shares of our common stock were outstanding
+under the 1997 Plan. No further options may be granted under the 1997 Plan. 
+In connection with
+our merger with the Iteris Subsidiary in 2004, we assumed the 1998 Stock
+Incentive Plan (the “1998 Plan”) of the Iteris Subsidiary and all outstanding
+options granted thereunder. As of March 31, 2010, options to purchase
+approximately 1.3 million shares of our common stock were outstanding under the
+1998 Plan. No further options may be granted under the 1998 Plan. 
+Certain options
+granted under the 2007 Plan, the 1997 Plan and the 1998 Plan (collectively, the
+“Plans”) provide for accelerated vesting of unvested options in the event of a
+change in control under certain circumstances. 
+A summary of
+activity in the Plans for the fiscal year ended March 31, 2010 is as
+follows: 
+Options 
+Weighted 
+Average 
+Exercise 
+Price Per 
+Share 
+Weigthed 
+Average 
+Remaining 
+Contractual 
+Life 
+Aggregate 
+Intrinsic 
+Value 
+(In thousands) 
+(Years) 
+(In thousands) 
+Options
+outstanding at March 31, 2009 
+3,314 
+$ 
+1.92 
+Granted 
+393 
+1.43 
+Exercised 
+(113 
+) 
+1.26 
+Forfeited 
+(47 
+) 
+2.30 
+Expired 
+(329 
+) 
+3.01 
+Options
+outstanding at March 31, 2010 
+3,218 
+$ 
+1.77 
+4.0 
+$ 
+550 
+Options
+exercisable at March 31, 2010 
+2,581 
+$ 
+1.76 
+2.9 
+$ 
+518 
+Vested
+and expected to vest at March 31, 2010 
+3,106 
+$ 
+1.77 
+3.8 
+$ 
+543 
+Options
+exercisable at March 31, 2010 pursuant 
+to a change-in-control 
+3,218 
+$ 
+1.77 
+4.0 
+$ 
+550 
+In September 2009,
+our stockholders approved an amendment to increase the number of shares of our
+common stock authorized and reserved for issuance under the 2007 Plan by
+800,000 shares to a total of 1,650,000 shares. At March 31, 2010, there
+were approximately 882,000 shares of common stock available for grant under
+this plan. 
+Stock-Based Compensation 
+The following
+table presents stock-based compensation expense that is included in each
+functional line item on our consolidated statements of income: 
+Year Ended March 31, 
+2010 
+2009 
+2008 
+(In thousands) 
+Cost
+of net sales 
+$ 
+9 
+$ 
+9 
+$ 
+3 
+Cost
+of contract revenues 
+39 
+38 
+14 
+Selling,
+general and administrative expense 
+300 
+297 
+266 
+Research
+and development expense 
+27 
+20 
+7 
+$ 
+375 
+$ 
+364 
+$ 
+290 
+54 
+Table
+of Contents 
+At March 31,
+2010, there was approximately $848,000 of total unrecognized compensation
+expense related to unvested stock options. This expense is expected to be
+recognized over a weighted-average period of approximately 3.2 years. If there
+are any modifications or cancellations of the underlying unvested stock
+options, we may be required to accelerate, increase or cancel any remaining
+unearned stock-based compensation expense. Future stock-based compensation
+expense and unearned stock-based compensation will increase to the extent that
+we issue additional stock options or other stock-based awards. 
+The grant date fair value of stock options granted was estimated using
+the following weighted-average assumptions: 
+Year Ended March 31, 
+2010 
+2009 
+2008 
+Expected
+life - years 
+7.0 
+7.0 
+7.0 
+Risk-free
+interest rate 
+3.2 
+% 
+3.3 
+% 
+3.8 
+% 
+Expected
+volatility of common stock 
+74 
+% 
+75 
+% 
+80 
+% 
+Dividend
+yield 
+— 
+% 
+— 
+% 
+— 
+% 
+A summary of certain fair value and intrinsic value
+information pertaining to our stock options is as follows: 
+Year Ended March 31, 
+2010 
+2009 
+2008 
+(In thousands, except per share amounts) 
+Weighted
+average grant date fair value per share of options
+granted 
+$ 
+1.01 
+$ 
+1.50 
+$ 
+1.83 
+Intrinsic
+value of options exercised 
+28 
+771 
+2,555 
+Employee Incentive Programs 
+Under the terms of a Profit Sharing Plan, we may contribute to a trust
+fund such amounts as are determined annually by the Board of Directors. No
+contributions were made during the years ended March 31, 2010, 2009 and
+2008. 
+In May 1990, we adopted a 401(k) Plan as an amendment and
+replacement of the former Associate Stock Purchase Plan that was an additional
+feature of the Profit Sharing Plan. Under the 401(k) Plan, eligible
+associates voluntarily contribute to the plan, up to IRS maximums, through
+payroll deductions. Under the provisions of the 401(k) Plan, associates
+have various investment choices, one of which is the purchase of Iteris common
+stock at market price. We match up to 90% of contributions, based on years of
+service, up to a stated limit. Beginning July 1, 2009, we temporarily
+suspended our matching contributions to the 401(k) Plan. Our matching
+contributions were approximately $220,000, $753,000 and $401,000 for the fiscal
+years ended March 31, 2010, 2009 and 2008, respectively. Beginning in April 2010,
+we reinstituted certain limited matching contributions to the 401(k) Plan. 
+10. Business Segments,
+Significant Customer and Geographic Information 
+We currently operate in three reportable segments: Roadway Sensors,
+Vehicle Sensors and Transportation Systems. The Roadway Sensors segment
+includes our Vantage and VersiCam vehicle detection systems for traffic
+intersection control, incident detection and certain highway traffic data
+collection applications. This segment also includes our Pico compact video
+detection system, which was designed primarily to respond to international
+video detection needs. The Vehicle Sensors segment includes our lane departure
+warning products and is comprised of all of our activities related to vehicle
+safety. The Transportation Systems segment includes transportation engineering
+and consulting services and the development of transportation management and
+traveler information systems for the ITS industry. The accounting policies of
+the reportable segments are the same as those described in the summary of
+significant accounting policies. Certain corporate expenses, including interest
+and amortization of intangible assets, are not allocated to the segments. The
+reportable segments are each managed separately because they manufacture and
+distribute distinct products or provide services with different processes. All
+segment revenues are derived from external customers. Segment assets are not
+disclosed because the discrete financial information provided to and reviewed
+by our chief operating decision maker does not separately identify segment
+assets. 
+55 
+Table
+of Contents 
+Selected financial information for our reportable segments for the
+fiscal years ended March 31, 2010, 2009 and 2008 is as follows: 
+Roadway 
+Sensors 
+Vehicle 
+Sensors 
+Transportation 
+Systems 
+Total 
+(In thousands) 
+Year Ended March 31, 2010 
+Product
+revenue 
+$ 
+25,341 
+$ 
+5,624 
+$ 
+— 
+$ 
+30,965 
+Service
+and other revenue 
+— 
+685 
+26,413 
+27,098 
+Stock-based
+compensation 
+37 
+30 
+61 
+128 
+Depreciation
+and amortization 
+234 
+83 
+221 
+538 
+Allocated
+goodwill 
+8,214 
+4,671 
+14,906 
+27,791 
+Segment
+income (loss) 
+3,158 
+(894 
+) 
+1,445 
+3,709 
+Year Ended March 31, 2009 
+Product
+revenue 
+$ 
+27,197 
+$ 
+9,913 
+$ 
+— 
+$ 
+37,110 
+Service
+and other revenue 
+— 
+1,317 
+30,932 
+32,249 
+Stock-based
+compensation 
+30 
+48 
+50 
+128 
+Depreciation
+and amortization 
+198 
+137 
+249 
+584 
+Allocated
+goodwill 
+8,197 
+4,671 
+14,906 
+27,774 
+Segment
+income 
+3,415 
+569 
+2,216 
+6,200 
+Year Ended March 31, 2008 
+Product
+revenue 
+$ 
+28,452 
+$ 
+10,016 
+$ 
+— 
+$ 
+38,468 
+Service
+and other revenue 
+— 
+1,858 
+24,837 
+26,695 
+Stock-based
+compensation 
+18 
+45 
+27 
+90 
+Depreciation
+and amortization 
+107 
+130 
+147 
+384 
+Allocated
+goodwill 
+8,197 
+4,671 
+14,906 
+27,774 
+Segment
+income 
+5,062 
+552 
+2,094 
+7,708 
+The following reconciles segment income to consolidated income before
+income taxes: 
+Year Ended March 31, 
+2010 
+2009 
+2008 
+(In thousands) 
+Segment income: 
+Total
+income from reportable segments 
+$ 
+3,709 
+$ 
+6,200 
+$ 
+7,708 
+Unallocated amounts: 
+Corporate
+and other expenses 
+(232 
+) 
+(346 
+) 
+(266 
+) 
+Amortization
+of intangible assets 
+(159 
+) 
+(147 
+) 
+(147 
+) 
+Other
+income, net 
+44 
+116 
+252 
+Interest
+expense, net 
+(264 
+) 
+(646 
+) 
+(1,284 
+) 
+Income
+before income taxes 
+$ 
+3,098 
+$ 
+5,177 
+$ 
+6,263 
+Significant Customer and Geographic Information 
+No single customer accounted for more than 10% of our total net sales
+and contract revenues for each of the fiscal years ended March 31, 2010, 2009
+and 2008. 
+No individual customer or government agency had a receivable balance at
+March 31, 2010 or 2009 greater than 10% of our total trade accounts
+receivable balances as of March 31, 2010 and 2009, respectively. 
+Our total net sales and contract revenues derived from either shipments
+to, or contract, service and other revenues from external customers located
+outside the U.S. approximated 8%, 15% and 12% for the fiscal years ended March 31,
+2010, 2009 and 2008, respectively. 
+Substantially all of our long-lived assets are held in the U.S. 
+56 
+Table of Contents 
+11. Quarterly Financial Data (Unaudited) 
+Total Net 
+Sales and 
+Contract 
+Revenues 
+Gross Profit 
+Net 
+Income 
+Basic 
+Earnings 
+per Share 
+Diluted 
+Earnings 
+per Share 
+(In thousands, except per share amounts) 
+Quarter Ended: 
+June 30,
+2009 
+$ 
+14,634 
+$ 
+5,582 
+$ 
+144 
+$ 
+0.00 
+$ 
+0.00 
+September 30,
+2009 
+14,865 
+6,570 
+543 
+0.02 
+0.02 
+December 31,
+2009 
+13,577 
+5,535 
+709 
+0.02 
+0.02 
+March 31,
+2010 
+14,987 
+6,472 
+807 
+0.02 
+0.02 
+$ 
+58,063 
+$ 
+24,159 
+$ 
+2,203 
+$ 
+0.06 
+* 
+$ 
+0.06 
+* 
+June 30,
+2008 
+$ 
+17,442 
+$ 
+7,752 
+$ 
+666 
+$ 
+0.02 
+$ 
+0.02 
+September 30,
+2008 
+19,066 
+7,875 
+1,067 
+0.03 
+0.03 
+December 31,
+2008 
+16,462 
+6,504 
+741 
+0.02 
+0.02 
+March 31,
+2009 
+16,389 
+5,788 
+8,000 
+0.23 
+0.23 
+$ 
+69,359 
+$ 
+27,919 
+$ 
+10,474 
+$ 
+0.31 
+* 
+$ 
+0.30 
+* 
+* Annual per share amounts may not agree to the sum of
+the quarterly per share amounts due to differences between average shares
+outstanding during the periods. 
+Exhibit Index 
+Exhibit 
+Number 
+Description 
+Where Located 
+3.1 
+Restated Certificate of
+Incorporation of the registrant 
+Exhibit 3.1
+to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
+September 30, 2009 as filed with the SEC on October 30, 2009 
+3.2 
+Certificate of
+Designations of Series A Junior Participating Preferred Stock 
+Exhibit 3.2
+to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
+September 30, 2009 as filed with the SEC on October 30, 2009 
+3.3 
+Bylaws of the registrant,
+as amended 
+Exhibit 4.2
+to the registrant’s Registration Statement on Form S-1 (Reg.
+No. 033-67932) as filed with the SEC on July 6, 1993 
+3.4 
+Certificates of Amendment
+to Bylaws of the registrant dated April 24, 1998 and August 10,
+2001 
+Exhibit 3.4
+to the registrant’s Annual Report on Form 10-K/A for the year ended
+March 31, 2003 as filed with the SEC on July 29, 2003 
+3.5 
+Certificate
+of Amendment to Bylaws of registrant dated September 9, 2004 
+Exhibit 3.1
+to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
+September 30, 2004 as filed with the SEC on November 15, 2004 
+3.6 
+Certificate
+of Amendment to Bylaws of registrant effective September 16, 2005 
+Exhibit 3.5
+to the registrant’s Annual Report on Form 10-K for the year ended
+March 31, 2007 
+3.7 
+Certificate
+of Amendment to Bylaws of registrant effective December 7, 2007 
+Exhibit 3.1
+to the registrant’s Current Report on Form 8-K as filed with the SEC on
+December 13, 2007 
+3.8 
+Certificate
+of Amendment to Bylaws of registrant, effective August 20, 2009 
+Exhibit 3.3
+to the registrant’s Current Report on Form 8-K as filed with the SEC on
+August 21, 2009 
+57 
+Table of Contents 
+4.1 
+Specimen
+of common stock certificate 
+Exhibit 4.1
+to registrant’s Registration Statement on Form 8-A as filed with the SEC
+on December 8, 2004 
+4.2 
+Rights
+Agreement dated August 20, 2009 between the registrant and Computershare
+Trust Company, N.A., which includes the form of Certificate of Designations
+for the Series A Junior Participating Preferred Stock, the form of Right
+Certificate, and Summary of Rights to Purchase Preferred Stock as exhibits
+thereto 
+Exhibit 4.1
+to the registrant’s Current Report on Form 8-K as filed with the SEC on
+August 21, 2009 
+10.1 
+Form of
+Indemnity Agreement entered into by the registrant and certain of its
+officers and directors 
+Exhibit 19.4
+to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
+September 30, 1988 
+10.2 
+Form of
+Indemnification Agreement entered into by the registrant and certain of its
+officers and directors 
+Exhibit 10.5
+to the registrant’s Annual Report on Form 10-K for the year ended
+March 31, 2004 as filed with the SEC on June 29, 2004 
+10.3* 
+1997
+Stock Incentive Plan (the “1997 Plan”) as amended on May 3, 2003, as
+further amended on December 15, 2004 
+Exhibit 10.32
+to the registrant’s Annual Report on Form 10-K for the year ended
+March 31, 2005 as filed with the SEC on July 14, 2005 
+10.4* 
+Form of Notice of
+Grant of Stock Option for 1997 Plan 
+Exhibit 99.2
+to the registrant’s Registration Statement on Form S-8 (File
+No. 333-30396) as filed with the SEC on February 14, 2000 
+10.5* 
+Form of
+Stock Option Agreement for the 1997 Plan 
+Exhibit 99.3
+to the registrant’s Registration Statement on Form S-8 (File
+No. 333-30396) as filed with the SEC on February 14, 2000 
+10.6* 
+Form of
+Addendum to Stock Option Agreement for 1997 Plan—Involuntary Termination
+Following Corporate Transaction or Change in Control 
+Exhibit 99.4
+to the registrant’s Registration Statement on Form S-8 (File
+No. 333-30396) as filed with the SEC on February 14, 2000 
+10.7* 
+Form of
+Addendum to Stock Option Agreement for 1997 Plan—Limited Stock Appreciation
+Rights 
+Exhibit 99.5
+to the registrant’s Registration Statement on Form S-8 (File
+No. 333-30396) as filed with the SEC on February 14, 2000 
+10.8* 
+Form of
+Stock Issuance Agreement for 1997 Plan 
+Exhibit 99.6
+to the registrant’s Registration Statement on Form S-8 (File
+No. 333-30396) as filed with the SEC on February 14, 2000 
+10.9* 
+Form of
+Addendum to Stock Issuance Agreement for 1997 Plan—Involuntary Termination
+Following Corporate Transaction/Change in Control 
+Exhibit 99.7
+to the registrant’s Registration Statement on Form S-8 (File
+No. 333-30396) as filed with the SEC on February 14, 2000 
+10.10* 
+Form of
+Notice of Grant of Automatic Stock Option for 1997 Plan—Initial Grant 
+Exhibit 99.8
+to Exhibit 99.8 to registrant’s Registration Statement on Form S-8
+(File No. 333-30396) as filed with the SEC on February 14, 2000 
+10.11* 
+Form of
+Notice of Grant of Automatic Stock Option for 1997 Plan—Annual Grant 
+Exhibit 99.9
+to the registrant’s Registration Statement on Form S-8 (File
+No. 333-30396) as filed with the SEC on February 14, 2000 
+10.12* 
+Form of
+Automatic Stock Option Agreement for 1997 Plan 
+Exhibit 99.10
+to the registrant’s Registration Statement on Form S-8 (File
+No. 333-30396) as filed with the SEC on February 19, 2000 
+58 
+Table of Contents 
+10.13* 
+Iteris
+Inc. 1998 Stock Incentive Plan (as amended on February 7, 2000) (“1998
+Plan”) 
+Exhibit 10.24
+to the registrant’s Annual Report on Form 10-K for the year ended
+March 31, 2005 as filed with the SEC on July 14, 2005 
+10.14* 
+Form of
+Notice of Grant for 1998 Plan, including forms of Option Agreement and Stock
+Purchase Agreement for the following directors and executive officers: Gregory
+McKhann, James S. Miele and Abbas Mohaddes 
+Exhibit 99.2
+to the registrant’s Registration Statement on Form S-8 (File
+No. 333-126834) as filed with the SEC on July 22, 2005 
+10.15* 
+Form of
+Addendum to Stock Option Agreement for 1998 Plan 
+Exhibit 99.3
+to the registrant’s Registration Statement on Form S-8 (File
+No. 333-126834) as filed with the SEC on July 22, 2005 
+10.16* 
+Form of
+1997 Stock Option Agreements 
+Exhibit 99.4
+to the registrant’s Registration Statement on Form S-8 (File No. 333-126834)
+as filed with the SEC on July 22, 2005 
+10.17* 
+Iteris, Inc.
+Deferred Compensation Savings Plan and Grantor Trust 
+Exhibit 10.31
+to the registrant’s Annual Report on Form 10-K for the year ended
+March 31, 2005 as filed with the SEC on July 14, 2005 
+10.18+ 
+Cooperative
+Agreement for Development, Manufacture, Marketing and Sale of Products to the
+Class 1 and Class 2 Vehicle Markets Incorporating Iteris’ LDWS
+Technology (Valeo Schalter and Sensoren GmbH) 
+Exhibit 10.1
+to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
+June 30, 2004 as filed with the SEC on August 16, 2004 
+10.19 
+Warrant
+Exercise Agreement dated September 27, 2006 by and among the registrant
+and Special Situations Fund III QP, L.P., Special Situations Fund III, L.P.,
+Special Situations Cayman Fund, L.P. and Special Situations Private Equity
+Fund, L.P. 
+Exhibit 10.1
+to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
+September 30, 2006 as filed with the SEC on November 14, 2006. 
+10.20 
+Registration
+Rights Agreement dated September 28, 2006 by and among the registrant
+and Special Situations Fund III QP, L.P., Special Situations Fund III, L.P.,
+Special Situations Cayman Fund, L.P. and Special Situations Private Equity
+Fund, L.P. 
+Exhibit 10.2
+to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
+September 30, 2006 as filed with the SEC on November 14, 2006. 
+10.21+ 
+National
+Intelligent Transportation Systems (ITS) Architecture Evolution and Support
+Award/Contract effective as of October 1, 2006 by and between the
+registrant and the Federal Highway Administration 
+Exhibit 10.3
+to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
+September 30, 2006 as filed with the SEC on November 14, 2006. 
+10.22* 
+Offer
+letter effective February 28, 2007 by and between the registrant and
+Abbas Mohaddes 
+Exhibit 10.1
+to the registrant’s Current Report on Form 8-K as filed with the SEC on
+March 6, 2007 
+10.23 
+Sublease
+Agreement, dated September 30, 2003, by and between Odetics, Inc.
+and Maij, Inc. 
+Exhibit 10.1
+to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
+June 30, 2007 as filed with the SEC on August 14, 2007 
+10.24 
+Office
+Lease Agreement, dated May 24, 2007, by and between Crown Carnegie
+Associates, LLC and Iteris, Inc. 
+Exhibit 10.2
+to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
+June 30, 2007 as filed with the SEC on August 14, 2007 
+10.25* 
+2007
+Omnibus Incentive Plan and forms of agreements 
+Appendix
+A to the registrant’s Definitive Proxy Statement on Schedule 14A as filed
+with the SEC on August 10, 2007 
+59 
+Table of Contents 
+10.26 
+Debenture
+Redemption Agreement, dated February 11, 2008, by and among Potomac
+Capital Partners, LP, Potomac Capital International Ltd. and
+Iteris, Inc. 
+Exhibit 10.1
+to the registrant’s Current Report on Form 8-K as filed with the SEC on
+February 15, 2008 
+10.27 
+Debenture
+Redemption Agreement, dated February 27, 2008, by and between
+Gruber & McBaine International and Iteris, Inc. 
+Exhibit 10.1
+to the registrant’s Current Report on Form 8-K as filed with the SEC on
+February 29, 2008 
+10.28 
+Debenture
+Redemption Agreement, dated February 27, 2008, by and between Lagunitas
+Partners, LP and Iteris, Inc. 
+Exhibit 10.2
+to the registrant’s Current Report on Form 8-K as filed with the SEC on
+February 29, 2008 
+10.29 
+Debenture
+Redemption Agreement, dated February 27, 2008, by and between Jon D. and
+Linda W. Gruber Trust and Iteris, Inc. 
+Exhibit 10.3
+to the registrant’s Current Report on Form 8-K as filed with the SEC on
+February 29, 2008 
+10.30* 
+Change
+in Control Agreement dated June 11, 2008 by and between James S. Miele
+and Iteris, Inc. 
+Exhibit 10.42
+to the registrant’s Annual Report on Form 10-K for the year ended
+March 31, 2008 as filed with the SEC on June 12, 2008 
+10.31 
+Amended
+and Restated Loan and Security Agreement dated February 4, 2009 by and
+between California Bank & Trust and the registrant 
+Exhibit 10.1
+to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
+December 31, 2008 as filed with the SEC on February 13, 2009 
+10.32 
+Debenture
+Redemption Agreement, dated October 17, 2008, by and between the
+registrant and certain affiliates of Bryant R. Riley 
+Exhibit 10.2
+to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
+December 31, 2008 as filed with the SEC on February 13, 2009 
+10.33 
+Debenture
+Redemption Agreement, dated October 27, 2008, by and between the
+registrant and each of Lloyd I. Miller, III, Lloyd I. Miller Trust A-4,
+Milfam I, L.P. and Milfam II, L.P. 
+Exhibit 10.3
+to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
+December 31, 2008 as filed with the SEC on February 13, 2009 
+10.34 
+Debenture
+Redemption Agreement, dated January 9, 2009, by and between the
+registrant and each of Irvin Kessler and Provident Premier Master Fund Ltd. 
+Exhibit 10.4
+to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
+December 31, 2008 as filed with the SEC on February 13, 2009 
+10.35 
+Separation
+Agreement and Release of All Claims, dated May 20, 2009, by and between
+Francis Memole and the registrant 
+Exhibit 10.45
+to the registrant’s Annual Report on Form 10-K for the year ended
+March 31, 2009 as filed with the SEC on June 12, 2009 
+10.36 
+Unsecured
+Promissory Note dated August 10, 2009 executed by MAXxess
+Systems, Inc. 
+Exhibit 10.1
+to the registrant’s Quarterly Report on Form 10-Q for the quarter ended
+June 30, 2009 as filed with the SEC on August 11, 2009 
+21 
+Subsidiaries
+of the registrant 
+Filed
+Herewith 
+23 
+Consent
+of Independent Registered Public Accounting Firm 
+Filed
+Herewith 
+31.1 
+Certification of the Chief
+Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of
+2002 
+Filed
+Herewith 
+31.2 
+Certification
+of the Chief Financial Officer Pursuant to Section 302 of the
+Sarbanes-Oxley Act of 2002 
+Filed
+Herewith 
+32.1 
+Certification
+of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as
+Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 
+Filed
+Herewith 
+32.2 
+Certification
+of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as
+Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 
+Filed
+Herewith 
+* Indicates a management
+contract or compensatory plan or arrangement 
++ Confidential treatment has
+been requested for certain confidential portions of this exhibit pursuant to Rule 24b-2
+of the Securities Exchange Act of 1934, as amended. In accordance with Rule 24b-2,
+these confidential portions have been omitted from the exhibit and filed separately
+with the SEC. 
+60
\ No newline at end of file
diff --git a/raw/filings/0000350868/2009/0001104659-10-029895/filing_metadata.csv b/raw/filings/0000350868/2009/0001104659-10-029895/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..1d700b072b1fc9caad1981e895aa0ae8a73da9b4
--- /dev/null
+++ b/raw/filings/0000350868/2009/0001104659-10-029895/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000350868,ITI,"ITERIS, INC.",10-K,2010-05-21,2010-03-31,2010-05-20T23:03:54.000Z,0001104659-10-029895,a10-10572_110k.htm,10-K,1904199,0,0,https://www.sec.gov/Archives/edgar/data/350868/000110465910029895/a10-10572_110k.htm,https://www.sec.gov/Archives/edgar/data/350868/000110465910029895/,2009,2009,1
diff --git a/raw/filings/0000350868/2009/0001104659-10-029895/item1.txt b/raw/filings/0000350868/2009/0001104659-10-029895/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..bece0a95456f9e571219db055c90d5a5933b2733
--- /dev/null
+++ b/raw/filings/0000350868/2009/0001104659-10-029895/item1.txt
@@ -0,0 +1,406 @@
+ITEM 1. BUSINESS 
+Overview 
+We are a leader in the
+traffic management market focused on the development and application of
+advanced technologies that reduce traffic congestion and improve the safety of
+surface transportation systems infrastructure. Additionally, we believe that
+our products and services, as well as sound traffic management, minimize the
+environmental impact of traffic congestion. By combining outdoor image
+processing, traffic engineering and information technology, we offer a broad
+range of Intelligent Transportation Systems (“ITS”) and driver safety solutions
+to customers worldwide. 
+We were originally incorporated in Delaware in 1987.
+Our principal executive offices are located at 1700 Carnegie Avenue, Santa Ana,
+California 92705, and our telephone number at that location is (949) 270-9400.
+Our Internet website address is www.iteris.com. Our annual reports on Form 10-K,
+quarterly reports on Form 10-Q and current reports on Form 8-K,
+together with amendments to these reports, are available on the “Investors”
+section of our website, free of charge, as soon as reasonably practicable after
+such material is electronically filed with, or furnished to, the Securities and
+Exchange Commission (“SEC”). The inclusion of our website address in this
+report does not include or incorporate by reference into this report any
+information on our website. 
+Products
+and Services 
+We currently operate in
+three reportable segments: Roadway Sensors, Vehicle Sensors and Transportation
+Systems. The Roadway Sensors segment includes, among other products, our
+Vantage, Versicam and Pico vehicle detection systems for traffic
+intersection control, incident detection and certain highway traffic data
+collection applications. The Vehicle Sensors segment includes our lane
+departure warning (“LDW”) products, including our AutoVue LDW system, and is
+comprised of all activities related to in-vehicle safety. The Transportation
+Systems segment includes transportation engineering and consulting services,
+and the development of transportation management and traveler information
+systems for the ITS industry. See Note 10 of Notes to Consolidated Financial
+Statements, included in Part IV, Item 15 of this report, for further
+details on our reportable segments. 
+Roadway Sensors. Our Roadway Sensors segment product line
+uses advanced image processing technology to capture and analyze video images
+through sophisticated algorithms, enabling vehicle detection and transmission
+of both video images and data using a wide range of communication technologies.
+Our Vantage video detection systems detect vehicle presence, count, speed,
+occupancy and other traffic data used in traffic management systems. Our
+Vantage systems give traffic managers the ability to mitigate roadway
+congestion by modifying traffic signal timing or detecting incidents quickly.
+Our VantageView software supplements our Vantage video detection systems by
+providing an integrated platform to manage and “see” video detection assets
+remotely over a network connection. Vantage video detection systems have been
+deployed by hundreds of agencies and are currently sold through a network of
+independent dealers in the United States (“U.S.”), Asia, Latin America, Europe
+and the Middle East. VersiCam, our integrated camera and processor video
+detection system, is a cost-efficient video detection system for smaller
+intersections that require only a few detection points. In December 2009,
+we introduced Pico, a compact video detection system that delivers superior
+vehicle detection in a small and economical framework, and was developed
+primarily to address international video detection needs. We anticipate that
+future growth domestically and internationally, particularly in developing
+countries, will be dependent in part on the continued adoption of above-ground
+video detection technologies, instead of in-pavement loop technology, to manage
+traffic. 
+2 
+Table of Contents 
+Our Roadway Sensors
+product line also includes the Abacus family of products, which has been
+designed with a blend of artificial intelligence and video detection algorithms
+that allow either fixed or pan-tilt-zoom cameras to be used for data collection
+and incident detection. Our Abacus products take advantage of the large number
+of existing installed closed-circuit television video feeds monitoring
+roadways, tunnels and bridges and at signalized intersections. This flexibility
+of using a broad range of cameras with an appropriate perspective allows for
+accurate data collection without the set-up and calibration required with other
+systems. 
+Vehicle Sensors. Our Vehicle Sensors segment addresses
+the leading causes of roadway fatalities: lane change, roadway departure and
+rear-end collision accidents. According to the National Highway Traffic Safety
+Administration (“NHTSA”), these three crash types result in more than 60% of
+the U.S.’s annual traffic fatalities and contribute to a considerable economic
+loss due to injuries, property damage, and decreased productivity. Early
+estimates by the NHTSA of motor vehicle traffic fatalities in 2009 were
+approximately 34,000. 
+We
+developed the world’s first production LDW system and offer a proven system
+that is available as an original equipment manufacturer (“OEM”) and aftermarket
+option on heavy trucks worldwide and as an option in certain passenger cars.
+Our LDW products utilize video detection images to detect when a vehicle begins
+to drift toward an unintended lane change. When this occurs, the unit
+automatically emits a distinctive rumble strip or other audible warning sound,
+alerting the driver to make a correction. To date, we have sold approximately
+79,000 LDW systems into the heavy truck market in Europe, North America and
+Asia. Our LDW systems are currently qualified as an option on certain heavy
+trucks, including Mercedes-Benz, MAN, Iveco, DAF, Scania, Freightliner and
+FUSO, as well as Neoplan and MAN luxury bus and coach lines. In North America,
+our LDW systems are sold primarily to truck fleets. 
+In March 2009,
+the European Union (“EU”) approved a mandate that sets better standards to
+improve road safety in Europe. The new mandated rules for safety
+technology includes systems such as electronic stability control, advanced
+emergency braking and LDW systems to be compulsory on heavy-duty trucks and
+buses to further reduce accident risks. LDW systems are expected to
+be mandatory in Europe on all new heavy truck models beginning in
+2013. We believe that in order for the 2013 EU mandate
+for active safety systems to have a positive impact on our sales, we need to
+establish long-term supplier agreements with our European OEM heavy truck
+customers. To date we have agreements to supply certain of our European heavy
+truck customers through 2012 and we are actively working on agreements with
+other heavy truck OEMs that extend through 2013 and beyond in order to meet the
+anticipated increase in demand. However, we cannot assure you that our efforts
+will be successful or that the expected increase in demand will occur. We believe that
+the expected 2013 EU mandate for LDW and other active safety systems, and an
+increasing overall awareness of the potential benefits of LDW, helps validate
+the long-term market opportunity for LDW systems in commercial vehicles. Additionally, in North America we plan to develop
+partnerships with other manufacturers and suppliers of safety devices for heavy
+trucks to jointly sell our LDW systems and provide our SafetyDirect software
+tool to North American trucking fleets. 
+We
+have entered into an exclusive license of our LDW technology to our strategic
+partner, Valeo Schalter and Sensuren GmbH (“Valeo”), for the passenger car
+market, resulting in sales to date of approximately 79,300 LDW systems for
+passenger cars. We and our partner have recently experienced a greater degree
+of competition in the passenger car market as several passenger car OEMs have
+introduced vehicle platforms with competing LDW systems. However, Valeo continues
+to pursue opportunities in the passenger car market. 
+In addition to our LDW systems, our Vehicle Sensors
+portfolio includes radar-based Forward Collision Warning (“FCW”) and Blind Spot
+Warning (“BSW”) systems for the North American truck market. We offer the FCW
+and BSW features through the resale of Delphi’s radar based systems, for which
+we are the exclusive North American dealer. Our portfolio also includes our
+internally-developed SafetyDirect software system, which can provide a single
+point of access to monitor and synchronize driver performance data on braking,
+stability control, following distances, and lane departure warnings for
+individual drivers as well as entire fleets. SafetyDirect uses information
+transmitted from the vehicle by the fleet’s onboard mobile communications
+system to provide fleet operators with a comprehensive view of the entire
+fleet, as well as the ability to drill down to detailed information on
+individual drivers and events. These products, together with our LDW products,
+combine to create a broad suite of active safety driver assistance features
+designed to help reduce the number of motor vehicle crashes and the severity of
+crash-related injuries. 
+Transportation Systems. Our Transportation Systems segment
+includes transportation engineering and consulting services focused on the
+planning, design, development and implementation of software-based systems that
+integrate sensors, video surveillance, computers and advanced communications
+equipment to enable public agencies to monitor, control and direct traffic
+flow, assist in the quick dispatch of emergency crews and distribute real-time
+information about traffic conditions. Our services include planning, design and
+implementation of surface transportation infrastructure systems. We perform
+analysis and study goods movement, commercial vehicle operations, travel demand
+forecasting and systems engineering, and identify mitigation measures to 
+3 
+Table of Contents 
+reduce traffic
+congestion. These services and systems have historically been primarily sold to
+local, state and national transportation agencies in the U.S.; however, during
+the fiscal year ended March 31, 2010 (“Fiscal 2010”), we began work on our
+first overseas contracts in Abu Dhabi and Dubai, and plan to continue to pursue
+additional international business. Our Transportation Systems segment is
+largely dependent upon governmental funding, and is affected by state and local
+budgetary issues. 
+Sales,
+Marketing and Principal Customers 
+We sell our Roadway
+Sensors products through indirect sales channels comprised of a strong network
+of independent dealers in the U.S. and Canada who sell integrated systems and
+related products to the traffic management market, as well as directly to the
+traffic management market using a combination of our own sales personnel and an
+outside sales organization. Our independent dealers are well-trained in, and
+primarily responsible for, sales, installation, set-up and support of our
+products, and maintain an inventory of demonstration traffic products from
+various manufacturers including our vehicle detection systems and sell directly
+to government agencies and installation contractors. These dealers often have
+long-term arrangements with local government agencies in their respective
+territories for the supply of various products for the construction and
+renovation of traffic intersections, and are generally well-known suppliers of
+high-quality ITS products to the traffic management market. We periodically
+hold technical training classes for our dealers and end users and maintain a
+full-time expert staff of customer support technicians throughout the U.S. to
+provide technical assistance when needed. When appropriate, we have the ability
+to modify or make changes to our dealer network to best suit the needs of the
+market and our customer base. In the states where we sell direct, we use our
+own expert staff to sell, oversee installations and set-up issues and support
+our products. 
+Our marketing strategy
+for our Vehicle Sensors segment is to establish our LDW products as the leading
+platform for in-vehicle video sensing for heavy trucks and passenger cars. We
+sell LDW systems directly to heavy truck manufacturers and to U.S. truck
+fleets, and our LDW system is currently offered as an option on certain heavy
+trucks, including Mercedes-Benz, MAN, Iveco, DAF, Scania, Freightliner and
+FUSO, as well as Neoplan and MAN luxury bus and coach lines. We market the
+licensing of our LDW technology to manufacturers of passenger automobiles
+through an exclusive strategic relationship with Valeo. In connection with this
+marketing effort, we provide specific contract engineering services, technical
+marketing and sales support to Valeo, which to date has enabled the launch of
+our LDW technology on three Infiniti car platforms, with a fourth platform
+expected in the summer of 2010. We plan to continue to provide technical
+marketing and sales support to Valeo in our efforts to win new OEM customers
+for the passenger car market, as well as contract engineering services related
+to the possible launch of new platforms that include our LDW system. 
+We market and sell our
+Transportation Systems services directly to government agencies pursuant to
+negotiated contracts that involve competitive bidding and specific
+qualification requirements. Most of our Transportation Systems contracts are
+with federal, state and municipal customers and generally provide for
+cancellation or renegotiation at the option of the customer upon reasonable
+notice and fees paid for modification. We use selected members of our
+engineering team on a regional basis to serve in sales and business development
+functions. Our Transportation Systems contracts generally involve long lead
+times and require extensive specification development, evaluation and price
+negotiations. 
+A large portion of our
+revenues are derived from sales to federal, state and local government
+agencies. We currently have a diverse customer base with no individual customer
+representing greater than 10% of our total net sales and contract revenues in
+Fiscal 2010, or in the fiscal years ended March 31, 2009 (“Fiscal 2009”)
+and March 31, 2008 (“Fiscal 2008”). Also refer to Note 10 of Notes to
+Consolidated Financial Statements, included in Part IV, Item 15 of
+this report. 
+Manufacturing and Materials 
+We use contract
+manufacturers to build subassemblies that are used in our sensors products.
+Additionally, we procure certain components from qualified suppliers, both
+globally and locally, and generally use multi-sourcing strategies when
+technically and economically feasible to mitigate supply risk. These
+subassemblies and components are delivered to our Santa Ana, California facility
+where they go through final assembly and testing prior to shipment to our
+customers. Certain of our key suppliers include CTS Electronics Manufacturing
+Solutions, Inc., SMS Technologies, Inc., Total Electronics LLC and
+Hitachi American Ltd-UB. Our manufacturing activities are conducted in
+approximately 9,000 square feet of space at our Santa Ana facility. Production
+volume at our subcontractors is based upon quarterly forecasts that we
+generally adjust on a monthly basis to control inventory levels. For LDW
+products sales to the passenger car market, all manufacturing has been and is
+expected to be performed by Valeo; however, we plan to continue to provide
+engineering support to Valeo. We typically do not manufacture any of the
+hardware used in the transportation management and traveler information systems
+that we design and implement. Our production facility is currently ISO 9001
+certified. 
+Customer
+Support and Services 
+We provide warranty
+service and support for our products, as well as follow-up service and support
+for which we charge separately. Such service revenue accounted for less than
+1.0% of total net sales and contract revenues for each of Fiscal 2010 and
+Fiscal 2009. We believe customer support is a key competitive factor. 
+4 
+Table of Contents 
+Backlog 
+Our total backlog of
+unfulfilled firm orders was approximately $30.6 million as of March 31,
+2010, which was comprised of $1.6 million related to Roadway Sensors, $600,000
+related to Vehicle Sensors and $28.4 million related to Transportation Systems.
+Substantially all of the backlog for Roadway Sensors and Vehicle Sensors is
+expected to be recognized as revenue in the fiscal year ending March 31,
+2011 (“Fiscal 2011”). We have historically recognized in the subsequent fiscal
+year between 50% to 70% of our fiscal year end Transportation Systems backlog,
+and currently expect that trend to continue for Fiscal 2011. The timing and
+realization of this backlog is subject to the inherent uncertainties of doing
+business with federal, state and local governments, particularly in view of
+budgetary constraints, cut-backs and other delays or reallocations of funding
+that these entities typically face. 
+Pursuant to the customary
+terms of our agreements with government contractors and other customers,
+customers can generally cancel or reschedule orders with little or no
+penalties. Lead times for the release of purchase orders often depend upon the
+scheduling and forecasting practices of our individual customers, which also
+can affect the timing of the conversion of our backlog into revenues. For these
+reasons, among others, our backlog at a particular date may not be indicative
+of our future revenues, in particular for our Roadway Sensors and Vehicle
+Sensors segments. 
+Product
+Development 
+Most of our product
+development activities are conducted at our principal facilities in Santa Ana.
+Our research and development costs and expenses were approximately $3.7 million
+for Fiscal 2010, $4.0 million for Fiscal 2009 and $3.6 million for Fiscal 2008.
+We expect to continue to pursue various product development programs and incur
+research and development expenditures in future periods. 
+We
+believe our engineering and product development capabilities are a competitive
+strength. We strive to continue to develop new products to meet the needs of
+the ever-changing ITS market as well as enhance and refine our existing product
+lines. Within the last twelve months we have introduced our VersiCam and
+VersiCam wireless products, Pico, Abacus and our new RZ-4 Advanced camera, as
+well as our RZ-4 Advanced Wide Dynamic Range camera, which significantly
+improves video detection performance in certain harsh lighting conditions. We
+believe that developing new offerings across our segments and enhancing,
+refining and marketing our existing products is a key component of strong
+organic growth and profitability. 
+Competition 
+We generally face
+significant competition in each of our target markets. Increased competition
+may result in price reductions, reduced gross margins and loss of market share,
+any of which could have a material adverse effect on our business, financial
+condition and results of operations. 
+In the market for our
+Roadway Sensors vehicle detection products, we compete with manufacturers and
+distributors of other above ground video camera detection systems such as Peek
+Traffic Corporation, Wavetronix LLC, Econolite Control Products, Inc.,
+Traficon, N.V., Image Sensing Systems, Inc. and other non-intrusive
+detection devices including microwave, infrared, ultrasonic and magnetic
+detectors, as well as manufacturers and installers of in-pavement inductive
+loop products, which have historically, and currently continue to be, the
+predominant detection system in this market. 
+In the market for our
+Vehicle Sensors systems, we believe that as a result of the expected 2013
+European mandate for LDW and other active safety systems, and an overall
+awareness of the potential benefits of LDW, that we will experience an even
+higher degree of competition from a variety of tier-one OEM suppliers and other
+potential market entrants, worldwide. Additionally, we and our strategic
+partner (Valeo) have recently experienced a greater degree of competition in
+the passenger car market as several passenger car OEMs have introduced vehicle
+platforms with competing LDW systems. We consider competitors in this market to
+include Delphi Automotive Systems Corporation, NEC Corporation and Hitachi Ltd.
+in Japan and Robert Bosch GmbH in Europe, Continental Tavis, Visteon and
+Takata, all of which currently have developed or are developing video sensor
+technologies for the vehicle industry that could be used for lane departure
+warning systems. 
+The Transportation
+Systems market is highly fragmented and is subject to evolving national and
+regional quality and safety standards. Our competitors vary in number, scope
+and breadth of the products and services they offer. Our competitors in
+advanced Transportation Systems include national corporations such as
+Transcore, Siemens, Telvent Farradyne, Kimley-Horn and Associates, Inc.
+and Delcan. Our competitors in transportation engineering, planning and design
+include major firms such as Parsons Brinkerhoff, Inc., URS, HNTB and
+Parsons Transportation Group, Inc., as well as many smaller regional
+engineering firms. 
+5 
+Table of Contents 
+In general, the markets
+for the products and services we offer are highly competitive and are
+characterized by rapidly changing technology and evolving standards. Many of
+our current and prospective competitors have longer operating histories,
+greater name recognition, access to larger customer bases and significantly
+greater financial, technical, manufacturing, distribution and marketing
+resources than us. As a result, they may be able to adapt more quickly to new
+or emerging standards or technologies or to devote greater resources to the
+promotion and sale of their products. It is also possible that new competitors
+or alliances among competitors could emerge and rapidly acquire significant
+market share. We believe that our ability to compete effectively in our target
+markets will depend on a number of factors, including the success and timing of
+our new product development, the compatibility of our products with a broad
+range of computing systems, product quality and performance, reliability,
+functionality, price and service and technical support. Our failure to provide
+services and develop and market products that compete successfully with those
+of other suppliers and consultants in our target markets would have a material
+adverse effect on our business, financial condition and results of operations. 
+Intellectual
+Property and Proprietary Rights 
+Our ability to compete
+effectively depends in part on our ability to develop and maintain the
+proprietary aspects of our technology. Our policy is to obtain appropriate
+proprietary rights protection for any potentially significant new technology
+acquired or developed by us. We currently hold ten U.S. patents, which expire
+commencing in 2012, relating to our outdoor image processing techniques used in
+our AutoVue LDW systems. Nine of these patents relate specifically to our LDW
+technology and provide a basis for enhanced functionality for rain sensing and
+improved performance. Our other U.S. patent was issued for an Electronic
+Traffic Monitor related to our Abacus product in the Roadway Sensors segment.
+We also have pending patent applications in Canada and the European Community
+for the Electronic Traffic Monitor. We cannot assure you that any new patents
+will be granted pursuant to these or subsequent applications. 
+In addition to patent
+laws, we rely on copyright and trade secret laws to protect our proprietary
+rights. We attempt to protect our trade secrets and other proprietary
+information through agreements with customers and suppliers, proprietary
+information agreements with our employees and consultants, and other similar
+measures. We do not have any material licenses or trademarks other than those
+relating to product names. We cannot be certain that we will be successful in
+protecting our proprietary rights. While we believe our patents, patent
+applications, software and other proprietary know-how have value, changing
+technology makes our future success dependent principally upon our employees’
+technical competence and creative skills for continuing innovation. 
+Litigation may be
+necessary in the future to enforce our proprietary rights, to determine the
+validity and scope of the proprietary rights of others, or to defend us against
+claims of infringement or invalidity by others. An adverse outcome in such
+litigation or similar proceedings could subject us to significant liabilities
+to third parties, require disputed rights to be licensed from others or require
+us to cease marketing or using certain products, any of which could have a
+material adverse effect on our business, financial condition and results of
+operations. In addition, the cost of addressing any intellectual property
+litigation claim, both in legal fees and expenses, as well as from the
+diversion of management’s resources, regardless of whether the claim is valid,
+could be significant and could have a material adverse effect on our business,
+financial condition and results of operations. 
+Employees 
+We refer to our employees
+as associates. As of May 7, 2010, we employed an aggregate of 221
+associates, including 53 associates in general management, administration and
+finance; 25 associates in sales and marketing; 116 associates in engineering
+and product development; 18 associates in operations, manufacturing and
+quality; and 9 associates in customer service. None of our associates are
+represented by a labor union, and we have never experienced a work stoppage. 
+Government
+Regulation 
+Our manufacturing
+operations are subject to various federal, state and local laws and
+regulations, including those restricting the discharge of materials into the
+environment. We are not involved in any pending or, to our knowledge,
+threatened governmental proceedings, which would require curtailment of our
+operations because of such laws and regulations. We continue to expend funds in
+connection with our compliance with applicable environmental regulations. These
+expenditures have not, however, been significant in the past, and we do not
+expect any significant expenditure in the near future. Currently, compliance
+with foreign laws has not had a material impact on our business and is not
+expected to have a material impact in the near future.
\ No newline at end of file
diff --git a/raw/filings/0000350868/2009/0001104659-10-029895/item13.txt b/raw/filings/0000350868/2009/0001104659-10-029895/item13.txt
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+++ b/raw/filings/0000350868/2009/0001104659-10-029895/item13.txt
@@ -0,0 +1,6 @@
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
+DIRECTOR INDEPENDENCE 
+The information under the
+captions “Corporate Governance — Director Independence” and “Certain
+Transactions,” appearing in our proxy statement for the 2010 Annual Meeting of
+Stockholders, is incorporated herein by reference.
\ No newline at end of file
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new file mode 100644
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--- /dev/null
+++ b/raw/filings/0000350868/2009/0001104659-10-029895/item9a.txt
@@ -0,0 +1,65 @@
+ITEM 9A(T). CONTROLS AND PROCEDURES 
+(a) Evaluation of
+disclosure controls and procedures. In accordance with Rule 13a-15(b) of the
+Securities Exchange Act of 1934, as of the end of the period covered by this
+Annual Report on Form 10-K, management evaluated, with the participation
+of the our President and Chief Executive Officer and the Chief Financial
+Officer, the effectiveness of the design and operation of our disclosure
+controls and procedures (as defined in Rule 13a-15(e) under the
+Exchange Act). Based upon their evaluation of these disclosure controls and
+procedures, the President and Chief Executive Officer and the Chief Financial
+Officer have concluded that our disclosure controls and procedures were
+effective as of the date of such evaluation in ensuring that information
+required to be disclosed in our Exchange Act reports is (1) recorded,
+processed, summarized and reported in a timely manner, and (2) accumulated
+and communicated to management, including the Company’s President and Chief
+Executive Officer and the Chief Financial Officer, as appropriate, to allow
+timely decisions regarding required disclosure. 
+(b) 
+Changes in internal control. There was no
+change in our internal control over financial reporting that occurred during
+the period covered by this Annual Report on Form 10-K that has materially
+affected, or is reasonably likely to materially affect, our internal control
+over financial reporting. 
+Inherent
+Limitations on Internal Control 
+A
+control system, no matter how well conceived and operated, can provide only
+reasonable, not absolute, assurance that the objectives of the control system
+are met. Further, the benefits of controls must be considered relative to their
+costs. Because of the inherent limitations in all control systems, no
+evaluation of controls can provide absolute assurance that all control issues
+and instances of management override or improper acts, if any, have been
+detected. These inherent limitations include the realities that judgments in
+decision making can be faulty, and that breakdowns can occur because of simple
+errors. Additionally, controls can be circumvented by the individual acts of
+some persons, by collusion of two or more people, or by management override of
+the control. The design of any system of controls is also based in part upon
+certain assumptions about the likelihood of future events, and there can be no
+assurance that any design will succeed in achieving its stated goals under all
+potential future conditions. Because of the inherent limitations in a
+cost-effective control system, misstatements due to management override, error
+or improper acts may occur and not be detected. Any resulting misstatement or
+loss may have an adverse and material effect on our business, financial
+condition and results of operations. 
+Management’s Report on Internal
+Control Over Financial Reporting 
+Our management is
+responsible for establishing and maintaining adequate internal control over
+financial reporting. Our internal control system was designed to provide
+reasonable assurance to management and the board of directors regarding the
+effectiveness of our internal control processes over the preparation and fair
+presentation of published financial statements. 
+We have assessed the
+effectiveness of our internal controls over financial reporting as of March 31,
+2010. In making this assessment, we used the criteria set forth by the
+Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in
+Internal Control—Integrated Framework. Based on our assessment, we believe
+that, as of March 31, 2010, our internal control over financial reporting
+is effective based on those criteria. 
+This annual report does not include an attestation
+report of our independent registered public accounting firm regarding internal
+control over financial reporting. Management’s report was not subject to
+attestation by our independent registered public accounting firm pursuant to
+the rules of the SEC that permit us to provide only management’s report in
+this annual report.
\ No newline at end of file
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index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000350868/2011/0001104659-12-042848/rp_note.txt b/raw/filings/0000350868/2011/0001104659-12-042848/rp_note.txt
new file mode 100644
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index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000350868/2013/0001047469-14-007351/filing.txt b/raw/filings/0000350868/2013/0001047469-14-007351/filing.txt
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@@ -0,0 +1,5279 @@
+10-K
+1
+a2221256z10-k.htm
+10-K
+Use these links to rapidly review the document 
+TABLE OF CONTENT1 
+TABLE OF CONTENT2 
+TABLE OF CONTENT3 
+Table of Contents 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+(Mark One) 
+ý 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended March 31, 2014 
+OR 
+o 
+TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the transition period
+from to 
+Commission file number 001-08762 
+ITERIS, INC. 
+(Exact Name of Registrant as Specified in Its Charter) 
+Delaware 
+(State or Other Jurisdiction 
+of Incorporation or Organization) 
+95-2588496 
+(I.R.S. Employer 
+Identification No.) 
+1700 Carnegie Ave., Santa Ana, California 92705 
+(Address of Principal Executive Offices) (Zip Code) 
+Registrant's
+Telephone Number, Including Area Code: (949) 270-9400 
+Securities
+registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Name of each exchange on which registered 
+Common Stock, $0.10 par value 
+NYSE MKT 
+Securities
+registered pursuant to Section 12(g) of the Act: None 
+Indicate
+by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
+Act. Yes o No ý 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the
+Act. Yes o No ý 
+Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act
+of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the
+past 90 days. Yes ý No o 
+Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to
+be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the
+registrant was required to submit and post such files). Yes ý No o 
+Indicate by a check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be
+contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this
+Form 10-K. ý 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See
+definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one): 
+Large accelerated filer o 
+Accelerated filer o 
+Non-accelerated filer o 
+(Do not check if a 
+smaller reporting company) 
+Smaller reporting company ý 
+Indicate
+by check mark whether the registrant is a shell company (as defined in Exchange Act
+Rule 12b-2). Yes o No ý 
+As of the last business day of the registrant's most recently completed second fiscal quarter, based on the closing sale price of the registrant's common stock on
+such date, the aggregate market value of the registrant's voting common stock held by nonaffiliates of the registrant was approximately $37,353,000. For the purposes of this calculation, shares owned
+by officers, directors and 10% stockholders known to the registrant have been deemed to be owned by affiliates. This determination of affiliate status is not necessarily a conclusive determination for
+other purposes. 
+As
+of August 27, 2014, there were 32,682,296 shares of our common stock outstanding. 
+DOCUMENTS INCORPORATED BY REFERENCE 
+None. 
+Table of Contents 
+ITERIS, INC. 
+ANNUAL REPORT ON FORM 10-K 
+FOR THE FISCAL YEAR ENDED MARCH 31, 2014 
+TABLE OF CONTENTS 
+PART I 
+ITEM 1. 
+BUSINESS 
+2 
+ITEM 1A. 
+RISK FACTORS 
+9 
+ITEM 1B. 
+UNRESOLVED STAFF COMMENTS 
+20 
+ITEM 2. 
+PROPERTIES 
+20 
+ITEM 3. 
+LEGAL PROCEEDINGS 
+20 
+ITEM 4. 
+MINE SAFETY DISCLOSURES 
+20 
+PART II 
+ITEM 5. 
+MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+21 
+ITEM 6. 
+SELECTED FINANCIAL DATA 
+22 
+ITEM 7. 
+MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+22 
+ITEM 7A. 
+QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
+37 
+ITEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+37 
+ITEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+37 
+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+37 
+ITEM 9B. 
+OTHER INFORMATION 
+39 
+PART III 
+ITEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+40 
+ITEM 11. 
+EXECUTIVE COMPENSATION 
+43 
+ITEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+49 
+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+51 
+ITEM 14. 
+PRINCIPAL ACCOUNTING FEES AND SERVICES 
+52 
+PART IV 
+ITEM 15. 
+EXHIBITS, FINANCIAL STATEMENT SCHEDULES 
+53 
+Unless
+otherwise indicated in this report, the "Company," "we," "us" and "our" refer to Iteris, Inc. and its wholly-owned subsidiaries. Abacus®,
+ClearPath™, ClearPath Agriculture™, ClearPath Weather™, Edge®, EdgeConnect™, iPerform®, iPeMS®, Iteris®,
+IterisPeMS™, Pico™, P10™, P100™, RZ-4™, SmartCycle®, SmartSpan®, Vantage®, VantageNext™,
+VantageView™, Vantage Vector®, Velocity™, and VersiCam™ are among the trademarks of Iteris, Inc. Any other trademarks or trade names mentioned
+herein are the property of their respective owners. 
+1 
+Table of Contents 
+Cautionary Statement 
+This report, including the following discussion and analysis, contains forward-looking statements (within the
+meaning of the Private Securities Litigation Reform Act of 1995) that are based on our current expectations, estimates and projections about our business and our industry, and reflect management's
+beliefs and certain assumptions made by us based upon information available to us as of the date of this report. When used in this report and the information incorporated herein by reference, the
+words "expect(s)," "feel(s)," "believe(s)," "should," "will," "may," "anticipate(s)," "estimate(s)," "could," "should," and similar expressions or variations of these words are intended to identify
+forward-looking statements. These forward-looking statements include, but are not limited to, statements regarding our anticipated growth, sales, revenue, expenses, profitability, capital needs,
+backlog and manufacturing capabilities, competition, the impact of any current or future litigation, the impact of recent accounting pronouncements, the applications for and acceptance of our products
+and services, and the status of our facilities and product development. These statements are not guarantees of future performance and are subject to certain risks and uncertainties that could cause
+our actual results to differ materially from those projected. You should not place undue reliance on these forward-looking statements that speak only as of the date hereof. We encourage you to
+carefully review and consider the various disclosures made by us which describe certain factors which could affect our business, including in " Risk
+Factors" set forth in Part I, Item 1A of this report, before deciding to invest in our company or to maintain or increase your investment. We undertake no obligation to revise or update
+publicly any forward-looking statement for any reason,
+including to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events. 
+PART I 
+ITEM 1. BUSINESS 
+Overview 
+We are a leading provider of intelligent information solutions for the traffic management market. We are focused on the development and
+application of advanced technologies and software-based information systems that reduce traffic congestion, provide measurement, management and predictive traffic analytics and improve the safety of
+surface transportation systems infrastructure. We also believe our products, services and solutions, in conjunction with sound traffic management, minimize the environmental impact of traffic
+congestion. By combining our unique intellectual property, products, decades of experience in traffic management, hyper-local weather solutions and information technologies, we offer a broad range of
+Intelligent Transportation Systems ("ITS") solutions to customers throughout the U.S. and internationally. 
+We
+were originally incorporated in Delaware in 1987. Our principal executive offices are located at 1700 Carnegie Avenue, Santa Ana, California 92705, and our telephone number at that
+location is (949) 270-9400. Our Internet website address is www.iteris.com. The inclusion of our website address in this report does not include or incorporate by reference into this
+report any information on, or accessible through, our website. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, together with
+amendments to these reports, are available on the "Investors" section of our website, free of charge, as soon as reasonably practicable after such material is electronically filed with, or furnished
+to, the Securities and Exchange Commission ("SEC"). 
+Products and Services 
+We currently operate in three reportable segments: Roadway Sensors, Transportation Systems and iPerform. The Roadway Sensors segment
+includes, among other products, our Vantage, VantageNext, VersiCam, Vantage Vector, SmartCycle, SmartSpan, P10, P100 and Abacus vehicle detection systems for traffic intersection control, incident
+detection and certain highway traffic data collection applications. 
+2 
+Table of Contents 
+The
+Transportation Systems segment includes transportation engineering and consulting services, and the development of transportation management and traveler information systems for the ITS industry.
+The iPerform segment includes our transportation performance measurement and information management solutions. The iPerform performance measurement solutions leverage its real-time data collection,
+diagnostic, fusion and warehousing platform to aggregate and compute performance measurements. This segment also offers our weather related ClearPath Weather management tools that allow users to
+create solutions to meet roadway maintenance decision needs. See Note 13 of Notes to Consolidated Financial Statements, included in Part IV, Item 15 of this report, for further
+details on our reportable segments. 
+Roadway Sensors 
+Our Roadway Sensors segment product line uses advanced image processing technology to capture and analyze video images through
+sophisticated algorithms, enabling vehicle detection and transmission of both video images and data using various communication technologies. 
+• Our Vantage and VantageNext video detection systems detect vehicle presence at intersections, as well as vehicle count,
+speed and other traffic data used in traffic management systems. Vantage video detection systems typically include up to four of our RZ-4 advanced cameras or our RZ-4 advanced wide dynamic range
+cameras and an EdgeConnect processor. Our Vantage systems give traffic managers the ability to mitigate roadway congestion by modifying traffic signal timing or detecting incidents quickly. Our
+VantageView software supplements our Vantage video detection systems by providing an integrated platform to manage and "see" video detection assets remotely over a network connection. 
+• Our Vantage Vector product is an all-in-one vehicle detection sensor with a wide range of capabilities, including stop
+bar detection, advanced-zone detection and sensing, which enable advanced safety and adaptive control applications. It includes all the proven benefits of Iteris video detection, including high
+accuracy, high availability remote viewing of video images, no trenching or pavement cutting for installation, bicycle detection capability and high precision for dilemma zone detection, by
+integrating the video field-of-view with radar sensing. Enhanced information includes the number of vehicles, speed and distance in user configurable zones that can be used for special applications. 
+• Our SmartSpan product uses proprietary dynamic zone stabilization algorithms and provides accurate and cost effective
+advance detection and stop-bar detection of vehicles at intersections equipped with span wire mounted signal lights. SmartSpan can be mounted on the same span wires holding the traffic signal without
+sacrificing detection accuracy. 
+• Our Vantage systems equipped with SmartCycle can effectively differentiate between bicycles and other vehicles with a
+single video detection camera, enabling more efficient signalized intersections and maximized traffic throughput. Agencies using bicycle timing can now benefit from bicycle-specific virtual detection
+zones that can be placed anywhere within the approaching traffic lanes, eliminating the need for separate bicycle-only detection systems. 
+• VersiCam, our integrated camera and processor video detection system, is a cost-efficient video detection system for
+smaller intersections that require only a few detection points. 
+• P10 and P100 (formerly, Pico), our compact video detection system, was developed primarily to address international video
+detection needs, and was designed for easy installation and configuration. 
+• Our Abacus products take advantage of the large number of existing installed closed-circuit television video feeds
+designed to monitor roadways, signalized intersections, tunnels and bridges 
+3 
+Table of Contents 
+to
+allow for data collection and incident detection without the set-up and calibration generally required with other systems. 
+We
+believe that future growth domestically and internationally, particularly in developing countries, will be dependent in part on the continued adoption of above-ground video detection
+technologies, instead of traditional in-pavement loop technology, to manage traffic. 
+We
+have historically experienced seasonality, particularly with respect to our Roadway Sensors revenues in our third and fourth fiscal quarters due to reductions in road construction and
+repairs during the winter months related to inclement weather conditions. 
+Transportation Systems 
+Our Transportation Systems segment includes transportation engineering and consulting services focused on the planning, design,
+development and implementation of software-based systems that integrate sensors, video surveillance, computers and advanced communications equipment to enable public agencies to monitor, control and
+direct traffic flow, assist in the quick dispatch of emergency crews and distribute real-time information about traffic conditions. Our services include planning, design and implementation of surface
+transportation infrastructure systems. We perform analysis and study goods movement, study commercial vehicle operations, provide travel demand forecasting and systems engineering, and identify
+mitigation measures to reduce traffic congestion. 
+Our
+Transportation Systems segment is largely dependent upon governmental funding and is affected by state and local budgetary issues. The current federal highway bill, which provides
+federal funding for highway, transit, safety and related transportation programs, will expire at the end of September 2014. The President signed a federal highway funding bill to keep the current
+federal highway bill operational until May of 2015. We expect the extension to encourage government agencies to include ITS technologies in transportation infrastructure projects to a greater degree
+than in previous legislation. In addition, various other funding mechanisms exist to support transportation infrastructure and related projects. These include bonds, dedicated sales and gas tax
+measures and other alternative funding sources. We believe the overall expansion of our Transportation Systems segment in the future will at least in part be dependent on the federal government's use
+of funds under the federal highway bill.
+Delays in the release of funding may prolong uncertainty regarding the allotment of transportation funds in federal, state and local budgets. We believe that prolonged uncertainty has adversely
+impacted in the past, and may adversely impact in the future, our Transportation Systems revenues and our overall financial performance in future periods. 
+iPerform 
+Our iPerform segment, formed during the first quarter of our fiscal year ended March 31, 2013 ("Fiscal 2013"), includes our
+performance measurement and information management solutions, including all of the operations of Berkeley Transportation Systems, Inc. ("BTS"), which we acquired in November 2011. BTS
+specializes in transportation performance measurement. The BTS performance measurement system leverages its real-time data collection, diagnostic, fusion and warehousing platform to aggregate and
+compute performance measurements. During the fiscal year ended March 31, 2012 ("Fiscal 2012"), we began the development of iPeMS (formerly, IterisPeMS). iPeMS is a state-of-the-art information
+management software suite that utilizes a wide range of data resources and analytical techniques to determine current and future traffic patterns, permitting the effective performance analysis and
+management of traffic infrastructure resources. This information can then be analyzed by traffic professionals to measure how a transportation network is performing and to identify potential areas of
+improvement. iPeMS is also capable of providing users with predictive traffic analytics and easy-to-use visualization and animation features based on historical traffic conditions. 
+4 
+Table of Contents 
+The
+iPerform segment also includes the operations of Meridian Environmental Technology, Inc. ("MET"), which we acquired in January 2011. MET specializes in 511/ advanced traveler
+information systems as well as ClearPath Weather management tools that allow users to create solutions to meet roadway maintenance decision needs. With the addition of MET, we have experienced
+seasonality particularly related to certain ClearPath Weather services in our first and second fiscal quarters, mainly because ClearPath Weather services are generally not required in the summer
+months when weather conditions are typically less severe. 
+iPerform
+is a market leader in performance management solutions for federal and state organizations. We intend to use our strong brand and deep experience in the traffic management
+market, as well as our market-specific intellectual property, to expand our leadership in data aggregation and analytics. By increasing investments in both technical and market development, we plan to
+focus on expanding the scope of our public sector solutions into the commercial marketplace. 
+Going
+forward, iPerform's solutions are expected to include incident management applications, arterial solutions, predictive traffic, and weather-based data and analytics for both public
+and commercial markets. We plan to fund these investments through internally generated cash flow from our Roadway Sensors and Transportation Systems operating segments, as well as revenues from our
+iPerform segment and our available cash if necessary. 
+Sales, Marketing and Principal Customers 
+We sell our Roadway Sensors products through direct and indirect sales channels. In the territories where we sell direct, we use a
+combination of our own sales personnel and an outside sales organization to sell, oversee installations and set-up issues and support our products. Our indirect sales channels are comprised of a
+network of independent dealers in the U.S. and certain foreign locations, who sell integrated systems and related products to the traffic management market. Our independent dealers are trained in, and
+primarily responsible for, sales, installation, set-up and support of our products, maintain an inventory of demonstration traffic products from various manufacturers and sell directly to government
+agencies and installation contractors. These dealers often have long-term arrangements with local government agencies in their respective territories for the supply of various products for the
+construction and renovation of traffic intersections, and are generally well-known suppliers of high-quality ITS products to the traffic management market. We periodically hold technical training
+classes for our dealers and end users and maintain a full-time staff of customer support technicians throughout the U.S. to provide technical assistance when needed. When appropriate, we have the
+ability to modify or make changes to our dealer network to accommodate the needs of the market and our customer base. 
+We
+market and sell our Transportation Systems services and solutions and iPerform solutions directly to government agencies pursuant to negotiated contracts that involve competitive
+bidding and specific qualification requirements. Most of our contracts are with federal, state and municipal customers and generally provide for cancellation or renegotiation at the option of the
+customer upon reasonable notice and fees paid for modification. We generally use selected members of our engineering, science and information technology teams on a regional basis to serve in sales and
+business development functions. Our contracts generally involve long lead times and require extensive specification development, evaluation and price negotiations. Additionally, we plan to focus on
+expanding the scope of our iPerform public sector solutions to sell into the commercial marketplace. 
+A
+large portion of our revenues are derived from sales to federal, state and local government agencies. We currently have, and historically have had, a diverse customer base. For our
+fiscal year ended March 31, 2014 ("Fiscal 2014"), one individual customer represented approximately 11% of our total revenues and no other individual customer represented greater than 10% of
+our total revenues. For Fiscal 2013, one individual customer represented approximately 13% of our total revenues and no 
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+other
+individual customer represented greater than 10% of our total revenues. For Fiscal 2012, no individual customer represented greater than 10% of our total revenues. Also refer to Note 13
+of Notes to Consolidated Financial Statements, included in Part IV, Item 15 of this report. 
+Manufacturing and Materials 
+We use contract manufacturers to build subassemblies that are used in our Roadway Sensors products. Additionally, we procure certain
+components from qualified suppliers, both locally and globally, and generally use multi-sourcing strategies when technically and economically feasible to mitigate supply risk. These subassemblies and
+components are typically delivered to our Santa Ana, California facility where they go through final assembly and testing prior to shipment to our customers. Our key suppliers include CTS Electronics
+Manufacturing Solutions, Inc., Sony Electronics, Inc. and LG Electronics, Inc. Our manufacturing activities are conducted in approximately 9,000 square feet of space at our Santa
+Ana facility. Production volume at our subcontractors is based upon quarterly forecasts that we generally adjust on a monthly basis to control inventory levels. We typically do not manufacture any of
+the hardware used in the transportation management and traveler information systems that we design and implement. Our production facility is currently ISO 9001 certified. 
+Customer Support and Services 
+We provide warranty service and support for our products, as well as follow-up service and support for which we charge separately. Such
+service revenue was not a material portion of our total revenues for each of Fiscal 2014, Fiscal 2013 and Fiscal 2012. We believe customer support is a key competitive factor. 
+Backlog 
+Our total backlog of unfulfilled firm orders was approximately $35.6 million as of March 31, 2014, which included
+$27.6 million related to Transportation Systems. Substantially the entire backlog for Roadway Sensors is expected to be recognized as revenue in the
+fiscal year ending March 31, 2015 ("Fiscal 2015"). In the past three fiscal years, we have recognized approximately 50% to 70% of our Transportation Systems backlog as of the end of a fiscal
+year in the subsequent fiscal year, and currently expect that trend to continue for the near future for both Transportation Systems and iPerform. 
+At
+March 31, 2013, we had backlog of approximately $38.6 million, which included $32.2 million related to Transportation Systems. 
+The
+timing and realization of our backlog is subject to the inherent uncertainties of doing business with federal, state and local governments, particularly in view of budgetary
+constraints, cut-backs and other delays or reallocations of funding that these entities typically face. 
+In
+addition, pursuant to the customary terms of our agreements with government contractors and other customers, our customers can generally cancel or reschedule orders with little or no
+penalties. Lead times for the release of purchase orders often depend upon the scheduling and forecasting practices of our individual customers, which also can affect the timing of the conversion of
+our backlog into revenues. For these reasons, among others, our backlog at a particular date may not be indicative of our future revenues, in particular for our Roadway Sensors segment. 
+Product Development 
+Most of our product development activities are conducted at our principal facilities in Santa Ana, California. Our research and
+development costs and expenses were approximately $4.0 million for Fiscal 2014, $3.1 million for Fiscal 2013 and $3.2 million for Fiscal 2012. We expect to continue to 
+6 
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+pursue
+various product development programs and incur research and development expenditures in future periods. 
+We
+believe our engineering and product development capabilities are a competitive strength. We strive to continue to develop new products to meet the needs of the ever-changing ITS
+market as well as enhance and refine our existing product lines. Since 2008, our Roadway Sensors segment has
+introduced our VantageNext, Vantage Vector, VersiCam and VersiCam wireless products, P10, P100, RZ-4 advanced camera and our RZ-4 advanced wide dynamic range camera, which significantly improve video
+detection performance in certain harsh lighting conditions, as well as upgrades to our Abacus and VantageView products. Additionally, during Fiscal 2012, we began development of our software based
+iPeMS performance measurement system, which continued through Fiscal 2014 and will continue during Fiscal 2015. We also plan to focus our development efforts on our ClearPath Weather and ClearPath
+Agriculture products. We believe that developing new offerings across our segments and enhancing, refining and marketing our existing products is a key component of strong organic growth and
+profitability. 
+Competition 
+We generally face significant competition in each of our target markets. Increased competition may result in price reductions, reduced
+gross margins and loss of market share, any of which could have a material adverse effect on our business, financial condition and results of operations. 
+In
+the market for our Roadway Sensors vehicle detection products, we compete with manufacturers and distributors of other above ground video camera detection systems and other
+non-intrusive detection devices, including microwave, infrared, radar, ultrasonic and magnetic detectors, as well as manufacturers and installers of in-pavement inductive loop products, which have
+historically, and currently continue to be, the predominant detection system in this market. 
+The
+markets in which our Transportation Systems segment operates is highly fragmented and subject to evolving national and regional quality, operations and safety standards. Our
+competitors vary in number, scope and breadth of the products and services they offer. Our competitors in advanced Transportation Systems include national corporations that generally offer expertise
+in traveler information, integration and transportation management. Our competitors in transportation engineering, planning and design include major regional firms, as well as many smaller local
+engineering firms. 
+The
+markets in which our iPeform segment operates vary from public sector customers who focus on performance measurement systems to help measure and manage the effectiveness of their
+transportation systems to commercial sector customers who ingest and disseminate traffic and weather related data, information and analytics through various consumer outlets. Our competitors vary in
+number, scope and breadth of the products and services they offer. In the public sector, we compete with some of the same transportation engineering, planning and design firms that also compete with
+our Transportation Systems segment. In the commercial sector, we compete with a variety of entities that currently provide traffic and/or weather related data to that market. 
+In
+general, the markets for the products and services we offer are highly competitive and are characterized by rapidly changing technology and evolving standards. Many of our current and
+prospective competitors have longer operating histories, greater name recognition, access to larger customer bases and significantly greater financial, technical, manufacturing, distribution and
+marketing resources than us. As a result, they may be able to adapt more quickly to new or emerging standards or technologies or to devote greater resources to the promotion and sale of their
+products. It is also possible that new competitors or alliances among competitors could emerge and rapidly acquire significant market share. We believe that our ability to compete effectively in our
+target markets will depend on a number of factors, including the success and timing of our new product development, the 
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+compatibility
+of our products with a broad range of computing systems, product quality and performance, reliability, functionality, price and service and technical support. Our failure to provide
+services and develop and market products that compete successfully with those of other suppliers and consultants in our target markets would have a material adverse effect on our business, financial
+condition and results of operations. 
+Intellectual Property and Proprietary Rights 
+Our ability to compete effectively depends in part on our ability to develop and maintain the proprietary aspects of our technology.
+Our policy is to obtain appropriate proprietary rights protection for any potentially significant new technology acquired or developed by us. We currently hold three U.S. patents, four foreign patent
+applications, six patent applications in the United States ("U.S."), and eight provisional patent filings. One U.S. patent, which expires in May 2019, is for general technology related to CMOS
+sensors. Two U.S. patents, which expire between 2014 and 2029, three foreign patent applications, three U.S. patent applications, and one provisional patent filing relate specifically to our Roadway
+Sensors technology. One pending foreign patent, three U.S. patent applications, and seven provisional patent filings relate specifically to our iPerform technology. We cannot be certain that any new
+patents will be granted pursuant to these or subsequent patent applications or provisional patent filings. 
+In
+addition to patent laws, we rely on copyright and trade secret laws to protect our proprietary rights. We attempt to protect our trade secrets and other proprietary information
+through agreements with customers and suppliers, proprietary information agreements with our employees and consultants, and other similar measures. We do not have any material licenses or trademarks
+other than those relating to product names. We cannot be certain that we will be successful in protecting our proprietary rights. While we believe our patents, patent applications, software and other
+proprietary know-how have value; changing technology makes our future success dependent principally upon our ability to successfully achieve continuing innovation. 
+Litigation
+may be necessary in the future to enforce our proprietary rights, to determine the validity and scope of the proprietary rights of others, or to defend us against claims of
+infringement or invalidity by others. An adverse outcome in such litigation or similar proceedings could subject us to significant liabilities to third parties, require disputed rights to be licensed
+from others or require us to cease marketing or using certain products, any of which could have a material adverse effect on our business, financial condition and results of operations. In addition,
+the cost of addressing any intellectual property litigation claim, both in legal fees and expenses, as well as from the diversion of management's resources, regardless of whether the claim is valid,
+could be significant and could have a material adverse effect on our business, financial condition and results of operations. 
+Employees 
+We refer to our employees as associates. As of March 31, 2014, we employed a total of 266 associates (of which 239 are
+full-time), including 56 associates in general management, administration and finance; 26 associates in sales and marketing; 154 associates in engineering and product development;
+14 associates in operations, manufacturing and quality assurance; and 16 associates in customer service. None of our associates are represented by a labor union, and we have never
+experienced a work stoppage. We believe our relations with our associates are good. 
+Government Regulation 
+Our manufacturing operations are subject to various federal, state and local laws and regulations, including those restricting the
+discharge of materials into the environment. We are not involved in any pending or, to our knowledge, threatened governmental proceedings, which would require curtailment 
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+of
+our operations because of such laws and regulations. We continue to expend funds in connection with our compliance with applicable environmental regulations. These expenditures have not, however,
+been significant in the past, and we do not expect any significant expenditure in the near future. Currently, compliance with foreign laws has not had a material impact on our business and is not
+expected to have a material impact in the near future. 
+ITEM 1A. RISK FACTORS 
+Our business is subject to a number of risks, some of which are discussed below. Other risks are presented
+elsewhere in this report and in the information incorporated by reference into this report. You should consider the following risks carefully in addition to the other information contained in this
+report and our other filings with the SEC, including our subsequent reports on Forms 10-Q and 8-K, before deciding to buy, sell or hold our common stock. The risks and uncertainties described
+below are not the only ones facing our company. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also affect our business operations. If any of
+these risks actually occurs, our business, financial condition, or results of operations could be seriously harmed. In that event, the market price for our common stock could decline and you may lose
+all or part of your investment. 
+The economic slowdown has reduced and delayed government funding for transportation infrastructure projects and initiatives, decreased availability of financial capital for our
+customers
+and adversely impacted real estate development, all of which have adversely impacted our revenues. Decreased consumer spending, the failure of certain financial
+institutions and businesses, concerns about the availability and cost of credit, and reduced corporate profits and capital spending have resulted in a downturn in worldwide economic conditions, as
+well as budgetary shortfalls at all levels of government. These unfavorable economic conditions are having, and are expected to continue to have, a negative impact on customer orders and government
+funding of infrastructure projects incorporating our products and services. Such factors have resulted and may continue to result in delays, cancellations and rescheduling of backlog and customer
+orders. In addition, the decline in the U.S. real estate market, particularly in new home and commercial construction, has adversely impacted new road construction and has had and may continue to have
+adverse effects on revenues. Any of the foregoing economic conditions may adversely affect our revenues in future periods and make it extremely difficult for our customers, our suppliers and us to
+accurately forecast and plan future business activities. Additionally, there was uncertainty in the past few years regarding allotment of government funds due to delays in the passage of a federal
+highway bill, which adversely impacted our revenues and overall financial performance. The current federal highway bill, which provides federal funding for highway, transit, safety and related
+transportation programs, will expire at the end of September 2014. The President signed a federal highway funding bill to keep the current federal highway bill operational until May of 2015. While we
+expect the extension to resolve the current uncertainty in federal funding, our Transportation Systems revenues and overall financial performance in future periods could be negatively affected if
+funding concerns persist. Furthermore, despite the extension of the federal highway bill, delays in the allocation of funds, the priority of infrastructure projects and the availability of funds for
+ITS related projects could continue to adversely impact our revenues and overall financial performance. 
+Because we depend on government contracts and subcontracts, we face additional risks related to contracting with federal, state and local governments, including budgetary issues
+and
+fixed price contracts. A significant
+portion of our revenues are derived from contracts with governmental agencies, either as a general contractor, subcontractor or supplier. We anticipate that revenue from government contracts will
+continue to remain a significant portion of our revenues. Government business is, in general, subject to special risks and challenges, including: 
+• delays in funding and uncertainty regarding the allocation of funds to state and local agencies from the U.S. federal
+government, delays in the expenditures from the federal highway bill and 
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+Table of Contents 
+delays
+or reductions in other state and local funding dedicated for transportation and ITS projects; 
+• other government budgetary constraints, cut-backs, delays or reallocation of government funding; 
+• performance bond requirements; 
+• long purchase cycles or approval processes; 
+• competitive bidding and qualification requirements; 
+• changes in government policies and political agendas; 
+• milestone requirements and liquidated damage provisions for failure to meet contract milestones; and 
+• international conflicts or other military operations that could cause the temporary or permanent diversion of government
+funding from transportation or other infrastructure projects. 
+Governmental
+budgets and plans are subject to change without warning. Certain risks of selling to governmental entities include dependence on appropriations and administrative allocation
+of funds, changes in governmental procurement legislation and regulations and other policies that may reflect political developments or agendas, significant changes in contract scheduling, intense
+competition for government business and termination of purchase decisions for the convenience of the governmental entity. Substantial delays in purchase decisions by governmental entities, and the
+current constraints on government budgets at the federal, state and local level, could cause our revenues and income to drop substantially or to fluctuate significantly between fiscal periods. 
+In
+addition, a number of our government contracts are fixed price contracts. As a result, we may not be able to recover any cost overruns we may incur. These fixed price contracts
+require us to estimate the total project cost based on preliminary projections of the project's requirements. The financial viability of any given project depends in large part on our ability to
+estimate these costs accurately and complete the project on a timely basis. In the event our costs on these projects exceed the fixed contractual amount, we will be required to bear the excess costs.
+Such additional costs would adversely affect our financial condition and results of operations. Moreover, certain of our government contracts are subject to termination or renegotiation at the
+convenience of the government, which could result in a large decline in our revenues in any given period. Our inability to address any of the foregoing concerns or the loss or renegotiation of any
+material government contract could seriously harm our business, financial condition and results of operations. 
+California state budgetary constraints may have a material adverse impact on us. The state of California has experienced, and is
+continuing to
+experience, a significant budget shortfall and other related budgetary issues and constraints. The state of California has historically been and is considered to be a key geographic region for our
+Roadway Sensors and Transportation Systems segments. Ongoing uncertainty as to the timing and accessibility of budgetary funding, changes in state funding allocations to local agencies and
+municipalities, or other delays in purchasing for, or commencement of, transportation projects have had and may continue to have a negative impact on our revenues and our income. 
+If we do not keep pace with rapid technological changes and evolving industry standards, we will not be able to remain competitive and there will be no demand for our
+products. Our markets are in general characterized by the following factors: 
+• rapid technological advances; 
+• downward price pressures in the marketplace as technologies mature; 
+• changes in customer requirements; 
+10 
+Table of Contents 
+• additional qualification requirements related to new products or components; 
+• frequent new product introductions and enhancements; 
+• inventory issues related to transition to new or enhanced models; and 
+• evolving industry standards and changes in the regulatory environment. 
+Our
+future success will depend upon our ability to anticipate and adapt to changes in technology and industry standards, and to effectively develop, introduce, market and gain broad
+acceptance of new products and product enhancements incorporating the latest technological advancements. 
+If we are unable to develop and introduce new products and product enhancements successfully and in a cost-effective and timely manner, or are unable to achieve market acceptance
+of our
+new products, our operating results would be adversely affected. We believe our revenue growth and future operating results will depend on our ability to complete
+development of new products and enhancements, introduce these products in a timely, cost-effective manner, achieve broad market acceptance of these products and enhancements, and reduce our production
+costs. We cannot guarantee the success of these products, and we may not be able to introduce any new products, including the iPeMS software, ClearPath Weather or any enhancements to our existing
+products on a timely basis, or at all. In addition, the introduction of any new products could adversely affect the sales of certain of our existing products. 
+We
+believe that we must continue to make substantial investments to support ongoing research and development in order to remain competitive. We need to continue to develop and introduce
+new products that incorporate the latest technological advancements in outdoor image processing hardware, software and camera technologies in response to evolving customer requirements. We cannot
+assure you that we will be able to adequately manage product transition issues. Our business and results of operations could be adversely affected if we do not anticipate or respond adequately to
+technological developments or changing customer requirements or if we cannot adequately manage inventory issues typically related to new product transitions and introductions. We cannot assure you
+that any such investments in research and development will lead to any corresponding increase in revenue. 
+We recently entered into the software development market and may be subject to additional challenges and additional costs and delays. We have only
+been in the business of software development for a few years and may experience development and technical challenges. Our business and results of operations could also be seriously harmed by any
+significant delays in our software development and updates. Certain of our new products could contain undetected design faults and software errors or "bugs" when first released by us, despite our
+testing. We may not discover these faults or errors until after a product has been installed and used by our customers. Any faults or errors in our existing products or in any new products may cause
+delays in product introduction and shipments, require design modifications or harm customer relationships, any of which could adversely affect our business and competitive position. We cannot assure
+you that our customer base will broadly accept any of our new products, product enhancements or software related offerings such as iPeMS and ClearPath Weather. In addition, the software development
+industry can frequently experience litigation concerning intellectual property disputes, which could be costly and distract our management. 
+The markets in which we operate are highly competitive and have many more established competitors, which could adversely affect our revenues or the market acceptance of our
+products. We compete with numerous other companies in our target markets including, but not limited to, large, multinational corporations and many smaller regional
+engineering firms. 
+We
+compete with existing, well-established companies and technologies in our Roadway Sensors segment, both domestically and abroad. Only a small portion of the intersection traffic
+market has adopted advanced video detection technologies, and our future success will depend in part upon 
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+Table of Contents 
+gaining
+broad market acceptance for video detection in this market. Certain technological barriers to entry make it difficult for new competitors to enter the market with competing video or other
+technologies; however, we are aware of new market entrants from time to time. Increased competition could result in loss of market share, price reductions and reduced gross margins, any of which could
+seriously harm our business, financial condition and results of operations. 
+The
+Transportation Systems market is highly fragmented and is subject to evolving national and regional quality and safety standards. Our competitors vary in size, number, scope and
+breadth of the products and services they offer, and include large multi-national engineering firms and smaller local regional firms. 
+The
+markets in which our iPeform segment operates vary from public sector customers who focus on performance measurement systems to help measure and manage the effectiveness of their
+transportation systems to commercial sector customers who ingest and disseminate traffic and weather related data, information and analytics through various consumer outlets. Our competitors vary in
+number, scope and breadth of the products and services they offer. In the public sector, we compete with some of the same transportation engineering, planning and design firms that also compete with
+our Transportation Systems segment. In the commercial sector, we compete with a variety of entities that currently provide traffic and/or weather related data to that market. 
+In
+all of our segments, many of our competitors have far greater name recognition and greater financial, technological, marketing, and customer service resources than we do. This may
+allow them to respond more quickly to new or emerging technologies and changes in customer requirements. It may also allow them to devote greater resources to the development, promotion, sale and
+support of their products than we can. Consolidations of end users, distributors and manufacturers in our target markets exacerbate this problem. As a result of the foregoing factors, we may not be
+able to compete effectively in our target markets and competitive pressures could adversely affect our business, financial condition and results of operations. 
+We may be unable to attract and retain key personnel, which could seriously harm our business. Due to the specialized nature of
+our business, we are
+highly dependent on the continued service of our executive officers and other key management, engineering and technical personnel. The loss of any of our officers, or any of our other executives or
+key members of management could adversely affect our business, financial condition, or results of operations. Our success will also depend in large part upon our ability to continue to attract, retain
+and motivate qualified engineering and other highly skilled technical personnel. The future success of our Transportation Systems segment will depend on our ability to hire additional qualified
+engineers, planners and technical personnel. The future success of our iPerform segment will depend on our ability to hire additional software developers, qualified engineers and technical personnel.
+Competition for qualified employees, particularly development engineers and software developers, is intense. We may not be able to continue to attract and retain sufficient numbers of such highly
+skilled employees. Our inability to attract and retain additional key employees or the loss of one or more of our current key employees could adversely affect our business, financial condition and
+results of operations. 
+Our profitability could be adversely affected if we are not able to maintain adequate utilization of our Transportation Systems workforce. The cost
+of providing our Transportation Systems engineering and consulting services, including the extent to which we utilize our workforce, affects our profitability. The rate at which we utilize our
+workforce is affected by a number of factors, including: 
+• our ability to transition employees from completed projects to new assignments and to hire and assimilate new employees; 
+• our ability to forecast demand for our services and thereby maintain an appropriate headcount in our various regions; 
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+Table of Contents 
+• our need to devote time and resources to training, business development, professional development and other
+non-chargeable activities; and 
+• our ability to match the skill sets of our employees to the needs of the marketplace. 
+Our failure to successfully bid on new contracts and renew existing contracts could reduce our revenues and profits. Our
+business depends on our
+ability to successfully bid on new contracts and renew existing contracts with private and public sector customers. Contract proposals and negotiations are complex and frequently involve a lengthy
+bidding and selection process, which are affected by a number of factors, such as market conditions, financing arrangements and required governmental approvals. For example, a customer may require us
+to provide a surety bond or letter of credit to protect the client should we fail to perform under the terms of the contract. If negative market conditions continue, or if we fail to secure adequate
+financing arrangements or the required governmental approval or fail to meet other required conditions, we may not be able to pursue particular projects, which could reduce or eliminate our
+profitability. 
+If we experience declining or flat revenues and we fail to manage such declines effectively, we may be unable to execute our business plan and may experience future weaknesses in
+our
+operating results. Based on our business objectives, and in order to achieve future growth, we will need to continue to add additional qualified personnel, and
+invest in additional research and development and sales and marketing activities, which could lead to increases in our expenses and future declines in our operating results. In addition, our past
+expansion has placed, and future expansion is expected to place, a significant strain on our managerial, administrative, operational, financial and other resources. If we are unable to manage these
+activities or any revenue declines successfully, our growth, our business, our financial condition and our results of operations could continue to be adversely affected. 
+We may be unable to maintain profitability on a quarterly or annual basis. We cannot assure you that we will be able to sustain
+or improve our
+financial performance, or that we will be able to continue to achieve profitability on a quarterly or annual basis in the future. Our ability to maintain profitability in future periods could be
+impacted by budgetary constraints, government and political agendas, economic instability and other items that are not in our control. Furthermore, we rely on operating profits from the Company's
+segments to fund investments in sales and marketing and research and development initiatives. We cannot assure you that at any given time these profits will sustain a sufficient level to completely
+support those investments. Most of our expenses are fixed in advance. As such, we generally are unable to reduce our expenses significantly in the short-term to compensate for any unexpected delay or
+decrease in anticipated revenues or increases in planned investments. As a result, we may experience operating losses and net losses in the future, which would make it difficult to fund our operations
+and achieve our business plan, and could cause the market price of our common stock to decline. 
+Our quarterly operating results fluctuate as a result of many factors. Therefore, we may fail to meet or exceed the expectations of securities analysts and investors, which could
+cause
+our stock price to decline. Our quarterly revenues and operating results have fluctuated and are likely to continue to vary from quarter to quarter due to a number
+of factors, many of which are not within our control. Factors that could affect our revenues include, among others, the following: 
+• delays in government contracts and funding from time to time and budgetary constraints at the federal, state and local
+levels; 
+• our ability to access stimulus funding, funding from the federal highway bill or other funding; 
+• declines in new home and commercial real estate construction and related road and other infrastructure construction; 
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+Table of Contents 
+• changes in our pricing policies and the pricing policies of our suppliers and competitors, pricing concessions on volume
+sales, as well as increased price competition in general; 
+• the long lead times associated with government contracts; 
+• the size, timing, rescheduling or cancellation of significant customer orders; 
+• our ability to control costs; 
+• our ability to raise additional capital; 
+• the mix of our products and services sold in a quarter, which has varied and is expected to continue to vary from time to
+time; 
+• seasonality due to winter weather conditions; 
+• seasonality with respect to revenues from our ClearPath Weather and related weather forecasting services due to the
+decrease in revenues generated for such services during the spring and summer time periods; 
+• our ability to develop, introduce, patent, market and gain market acceptance of new products, applications and product
+enhancements in a timely manner, or at all; 
+• market acceptance of the products incorporating our technologies and products; 
+• the introduction of new products by competitors; 
+• the availability and cost of components used in the manufacture of our products; 
+• our success in expanding and implementing our sales and marketing programs; 
+• the effects of technological changes in our target markets; 
+• the amount of our backlog at any given time; 
+• the nature of our government contracts; 
+• decrease in revenues derived from key or significant customers; 
+• deferrals of customer orders in anticipation of new products, applications or product enhancements; 
+• risks and uncertainties associated with our international business; 
+• general economic and political conditions; 
+• international conflicts and acts of terrorism; and 
+• other factors beyond our control, including but not limited to, natural disasters. 
+Due
+to all of the factors listed above as well as other unforeseen factors, our future operating results could be below the expectations of securities analysts or investors. If that
+happens, the trading price of our common stock could decline. As a result of these quarterly variations, you should not rely on quarter-to-quarter comparisons of our operating results as an indication
+of our future performance. 
+We may be subject to traffic related litigation. The traffic industry in general is subject to litigation claims due to the
+nature of personal
+injuries that result from traffic accidents. As a provider of traffic engineering services, products and solutions, we are, and could in the future continue to be, from time to time, subject to
+litigation for traffic related accidents, even if our products or services did not cause the particular accident. While we generally carry insurance against these types of claims, some claims may not
+be covered by insurance or the damages resulting from such litigation could exceed our insurance coverage limits. In the event that we are required to pay significant damages as a result of 
+14 
+Table of Contents 
+one
+or more lawsuits that are not covered by insurance or exceed our coverage limits, it could materially harm our business, financial condition or cash flows. Even defending against unsuccessful
+claims could cause us to incur significant expenses and result in a diversion of management's attention. 
+We may experience production gaps that could materially and adversely impact our sales and financial results and the ultimate acceptance of our
+products. It is possible that we could experience unforeseen quality control issues or part shortages as we adjust production to meet current demand for our
+products. We have historically used single suppliers for certain significant components in our products. Should any such delay or disruption occur, or should a key supplier discontinue operations
+because of the current economic climate, our future sales will likely be materially and adversely affected. Additionally, we rely heavily on select contract manufacturers to produce many of our
+products and do not have any long-term contracts to guarantee supply of such products. Although we believe our contract manufacturers have sufficient capacity to meet our production schedules for the
+foreseeable future and we believe we could find alternative contract manufacturing sources for many of our products, if necessary, we could experience a production gap if for any reason our contract
+manufacturers were unable to meet our production requirements and our cost of goods sold could increase, adversely affecting our margins. 
+Our use of the percentage of completion method of accounting for our Transportation Systems revenues could result in a reduction or reversal of previously recorded revenues and
+profits. A significant portion of Transportation Systems revenues are measured and recognized using the percentage of completion method of accounting. Our use of
+this accounting method results in recognition of revenues and profits proportionally over the life of a contract, based generally on the proportion of costs incurred to date to total costs expected to
+be incurred for the entire project. The effects of revisions to revenues and estimated costs are recorded when the amounts are known or can be reasonably estimated. Such revisions could occur in any
+period and their effects could be material. Although we have historically made reasonably reliable estimates of the progress towards completion of long-term engineering, program management,
+construction management or construction contracts, the uncertainties inherent in the estimating process make it possible for actual costs to vary materially from estimates, including reductions or
+reversals of previously recorded revenues and profits. 
+We may engage in acquisitions of companies or technologies that may require us to undertake significant capital infusions and could result in disruptions of our business and
+diversion of
+resources and management attention. We have completed three acquisitions since April 2009 and, in the future, we may acquire additional complementary businesses,
+products, and technologies. Acquisitions may require significant capital infusions and, in general, acquisitions also involve a number of special risks, including: 
+• potential disruption of our ongoing business and the diversion of our resources and management's attention; 
+• the failure to retain or integrate key acquired personnel; 
+• the challenge of assimilating diverse business cultures, and the difficulties in integrating the operations, technologies
+and information system of the acquired companies; 
+• increased costs to improve managerial, operational, financial and administrative systems and to eliminate duplicative
+services; 
+• the incurrence of unforeseen obligations or liabilities; 
+• potential impairment of relationships with employees or customers as a result of changes in management; and 
+• increased interest expense and amortization of acquired intangible assets, as well as unanticipated accounting charges. 
+15 
+Table of Contents 
+Our
+competitors are also soliciting potential acquisition candidates, which could both increase the price of any acquisition targets and decrease the number of attractive companies
+available for acquisition. Acquisitions may also materially and adversely affect our operating results due to large write-offs, contingent liabilities, substantial depreciation, deferred compensation
+charges or intangible asset amortization, or other adverse tax or accounting consequences. We cannot assure you that we will be able to identify or consummate any additional acquisitions, successfully
+integrate any acquisitions or realize the benefits anticipated from any acquisition. 
+Our international business operations may be threatened by many factors that are outside of our control. While we historically
+have had limited
+international sales, revenues and operations experience, we began work on our first overseas contracts in the United Arab Emirates in the fiscal year ended March 31, 2010. We plan to expand our
+international efforts in the future with respect to all of our segments, and in particular, plan to expand our distribution channels in Latin America and the Middle East. We cannot assure you that we
+will be successful in our expansion efforts. International operations subject us to various inherent risks including, among others: 
+• political, social and economic instability, as well as international conflicts and acts of terrorism; 
+• bonding requirements for certain international projects; 
+• longer accounts receivable payment cycles; 
+• import and export license requirements and restrictions of the U.S. and each other country in which we operate; 
+• currency fluctuations and restrictions, and our ability to repatriate currency from certain foreign regions; 
+• unexpected changes in regulatory requirements, tariffs and other trade barriers or restrictions; 
+• required compliance with existing and new foreign regulatory requirements and laws, more restrictive labor laws and
+obligations, including but not limited to the U.S. Foreign Corrupt Practices Act; 
+• difficulties in managing and staffing international operations; 
+• potentially adverse tax consequences; and 
+• reduced protection for intellectual property rights in some countries. 
+Substantially
+all of our international sales are denominated in U.S. dollars. As a result, an increase in the relative value of the dollar could make our products more expensive and
+potentially less price competitive in international markets. We do not currently engage in any transactions as a hedge against risks of loss due to foreign currency fluctuations. 
+Any
+of the factors mentioned above may adversely affect our future international revenues and, consequently, affect our business, financial condition and operating results. Additionally,
+as we pursue the expansion of our international business, certain fixed and other overhead costs could outpace our revenues, thus adversely affecting our results of operations. We may likewise face
+local competitors in certain international markets who are more established, have greater economies of scale and stronger customer relationships. Furthermore, as we increase our international sales,
+our total revenues may also be affected to a greater extent by seasonal fluctuations resulting from lower sales that typically occur during the summer months in Europe and other parts of the world. 
+If our internal controls over financial reporting do not comply with the requirements of the Sarbanes-Oxley Act, our business and stock price could be adversely
+affected. Section 404 of the Sarbanes-Oxley Act of 2002 currently requires us to evaluate the effectiveness of our internal controls over financial
+reporting at the end of each fiscal year and to include a management report assessing the effectiveness 
+16 
+Table of Contents 
+of
+our internal controls over financial reporting in all annual reports. In connection with the preparation of our financial statements for Fiscal 2014, we determined that we had several significant
+deficiencies relating to our accounting for consulting services revenues that constitute a material weakness in our internal control over financial reporting, such that there is a reasonable
+possibility that a material misstatement of our financial statements will not be prevented or detected on a timely basis, and that our internal control over financial reporting was not effective as of
+the end of Fiscal 2014. 
+In
+order to improve and to maintain the effectiveness of our internal control over financial reporting and disclosure controls and procedures, we have begun the process of remediating
+this material weakness. However, this process will take time and may require significant additional resources, including the hiring of additional personnel and improvements to or upgrades of our
+enterprise systems. We cannot assure you that such additional resources will remedy the material weakness in a timely fashion or at all. In addition, such remediation efforts may increase our selling,
+general and administrative expenses and negatively affect our financial results. As a result of this and similar activities, management's attention may also be diverted from other business concerns,
+which could have an adverse effect on our business, financial condition and results of operations. If we are unable to remediate this material weakness, or in the future experience one or more
+additional material weaknesses, our ability to report our financial condition and results of operations accurately and in a
+timely manner in the future may be adversely affected and could adversely affect the market price of our common stock. 
+As
+a smaller reporting company, for Fiscal 2014, we were exempt from the auditor attestation requirement over our internal control over financial reporting; however, to the extent we do
+not qualify as a non-accelerated filer or smaller reporting company in subsequent fiscal years, we will be subject to the auditor attestation requirement under Section 404(b) of the
+Sarbanes-Oxley Act. In such an event, we may not be able to complete the work required for such attestation on a timely basis and, even if we timely complete such requirements, our independent
+registered public accounting firm may still conclude that our internal controls over financial reporting are not effective. 
+Our
+management, including our CEO and CFO, does not expect that our internal controls over financial reporting will prevent all errors and all fraud. A control system, no matter how well
+designed and operated, can provide only reasonable, not absolute, assurance that the control system's objectives will be met. Further, the design of a control system must reflect the fact that there
+are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide
+absolute assurance that all control issues and instances of fraud, if any, within Iteris have been or will be detected. These inherent limitations include the realities that judgments in
+decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Controls can also be circumvented by the individual acts of some persons, by collusion of two or more
+people, or by management override of the controls. The design of any system of controls is based in part on certain assumptions about the likelihood of future events, and we cannot assure you that any
+design will succeed in achieving its stated goals under all potential future conditions. Over time, our controls may become inadequate because of changes in conditions or deterioration in the degree
+of compliance with policies or procedures. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. 
+We may not be able to adequately protect or enforce our intellectual property rights, which could harm our competitive position. If we are not able
+to adequately protect or enforce the proprietary aspects of our technology, competitors could be able to access our proprietary technology and our business, financial condition and results of
+operations will likely be seriously harmed. We currently attempt to protect our technology through a combination of patent, copyright, trademark and trade secret laws, employee and third party
+nondisclosure agreements and similar means. Despite our efforts, other parties may attempt to disclose, obtain or use our technologies or systems. Our competitors may also 
+17 
+Table of Contents 
+be
+able to independently develop products that are substantially equivalent or superior to our products or design around our patents. In addition, the laws of some foreign countries do not protect our
+proprietary rights as fully as do the laws of the U.S. As a result, we may not be able to protect our proprietary rights adequately in the U.S. or abroad. 
+Litigation
+may be necessary in the future to enforce our intellectual property rights or to determine the validity and scope of the proprietary rights of others. Litigation may also be
+necessary to defend against claims of infringement or invalidity by others. An adverse outcome in litigation or any similar proceedings could subject us to significant liabilities to third parties,
+require us to license disputed rights from others or require us to cease marketing or using certain products or technologies. We may not be able to obtain any licenses on terms acceptable to us, or at
+all. We also may have to indemnify certain customers or strategic partners if it is determined that we have infringed upon or misappropriated another party's intellectual property. Our recent
+expansion into software development activities may subject us to increased possibility of litigation. Any of the foregoing could adversely affect our business, financial condition and results of
+operations. In addition, the cost of addressing any intellectual property litigation claim, including legal fees and expenses, and the diversion of management's attention and resources, regardless of
+whether the claim is valid, could be significant and could seriously harm our business, financial condition and results of operations. 
+We may need to raise additional capital in the future, which may not be available on terms acceptable to us, or at all. We have
+historically
+experienced volatility in our earnings and cash flows from operations from year to year. Although we have a revolving line of credit, should we have an event of default, which includes, among other
+things, a failure to meet certain financial covenants and a material adverse change in the business, the bank could choose to limit or take away our ability to borrow these or any funds. Should this
+occur, or if the credit markets further tighten or our business declines, we may need or choose to raise additional capital to repay indebtedness, pursue acquisitions or expand our operations. Such
+additional capital may be raised through bank borrowings, or other debt or equity financings. We cannot assure you that any additional capital will be available on a timely basis, on acceptable terms,
+or at all, and such additional financing may result in further dilution to our stockholders. 
+Our
+capital requirements will depend on many factors, including, but not limited to: 
+• market acceptance of our products and product enhancements, and the overall level of sales of our products; 
+• our ability to control costs; 
+• the supply of key components for our products; 
+• our ability to increase revenue and net income; 
+• increased research and development expenses and sales and marketing expenses; 
+• our need to respond to technological advancements and our competitors' introductions of new products or technologies; 
+• capital improvements to new and existing facilities and enhancements to our infrastructure and systems; 
+• potential acquisitions of businesses and product lines; 
+• our relationships with customers and suppliers; 
+• government budgets, political agendas and other funding issues, including potential delays in government contract awards; 
+18 
+Table of Contents 
+• our ability to successfully negotiate credit arrangements with our bank and the state of the financial markets, in
+general; and 
+• general economic conditions, including the effects of the current economic slowdown and international conflicts. 
+If
+our capital requirements are materially different from those currently planned, we may need additional capital sooner than anticipated. If additional funds are raised through the
+issuance of equity or convertible debt securities, the percentage ownership of our stockholders will be reduced and such securities may have rights, preferences and privileges senior to our common
+stock. Additional equity or debt financing may not be available on favorable terms, on a timely basis, or at all. If adequate funds are not available or are not available on acceptable terms, we may
+be unable to continue our operations as planned, develop or enhance our products, expand our sales and marketing programs, take advantage of future opportunities or respond to competitive pressures. 
+The trading price of our common stock is highly volatile. The trading price of our common stock has been subject to wide
+fluctuations in the past.
+Since April 2012, our common stock has traded at prices as low as $1.25 per share and as high as $2.50 per share. The market price of our common stock could continue to fluctuate in the future in
+response to various factors, including, but not limited to: 
+• quarterly variations in operating results; 
+• our ability to control costs, improve cash flow and sustain profitability; 
+• our ability to raise additional capital; 
+• shortages announced by suppliers; 
+• announcements of technological innovations or new products or applications by our competitors, customers or us; 
+• transitions to new products or product enhancements; 
+• acquisitions of businesses, products or technologies; 
+• the impact of any litigation; 
+• changes in investor perceptions; 
+• government funding, political agendas and other budgetary constraints; 
+• changes in earnings estimates or investment recommendations by securities analysts; and 
+• international conflicts, political unrest and acts of terrorism. 
+The
+stock market in general has from time to time experienced volatility, which has often affected the market prices of equity securities of many technology companies. This volatility
+has often been unrelated to the operating performance of these companies. These broad market fluctuations may adversely affect the market price of our common stock. In the past, companies that have
+experienced volatility in the market price of their securities have been the subject of securities class action litigation. If we were to become the subject of a class action lawsuit, it could result
+in substantial losses and divert management's attention and resources from other matters. 
+Certain provisions of our charter documents may discourage a third party from acquiring us and may adversely affect the price of our common
+stock. Certain provisions of our certificate of incorporation could make it difficult for a third party to acquire us, even though an acquisition might be
+beneficial to our stockholders. Such provisions could limit the price that investors might be willing to pay in the future for shares of our common stock. Under the terms of our certificate of
+incorporation, our Board of Directors is authorized to issue, without stockholder approval, up to 2,000,000 shares of preferred 
+19 
+Table of Contents 
+stock
+with voting, conversion and other rights and preferences superior to those of our common stock. In August 2009, we adopted a new stockholder rights plan and declared a dividend of preferred
+stock purchase rights to our stockholders. Generally, the stockholder rights plan provides that if a person or group acquires 15% or more of our common stock, subject to certain exceptions and under
+certain circumstances, the rights may be exchanged by us for common stock or the holders of the rights, other than the acquiring person or group, could acquire additional shares of our capital stock
+at a discount off of the then current market price. Such exchanges or exercise of rights could cause substantial dilution to a particular acquirer and discourage the acquirer from pursuing our
+company. The mere existence of a stockholder rights plan often delays or makes a merger, tender offer or other acquisition more difficult. 
+ITEM 1B. UNRESOLVED STAFF COMMENTS 
+None. 
+ITEM 2. PROPERTIES 
+Our headquarters and principal operations are housed in approximately 52,000 square feet of leased office, manufacturing and warehouse
+space located in Santa Ana, California. In February 2014, we entered into an amendment to the lease for the facility to reduce the size of the leased premises to approximately 41,000 rentable square
+feet and extend the term of the lease through March 2022. For additional information regarding our obligations under property leases, see Note 9 of Notes to Consolidated Financial Statements,
+included in Part IV, Item 15 of this report. 
+ITEM 3. LEGAL PROCEEDINGS 
+The information set forth under the heading "Litigation and Other Contingencies" under Note 9 of Notes to Consolidated Financial
+Statements, included in Part IV, Item 15 of this report, is incorporated herein by reference. 
+ITEM 4. MINE SAFETY DISCLOSURES 
+Not applicable. 
+20 
+Table of Contents 
+PART II 
+ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+Market Information and Holders 
+Our common stock is traded on the NYSE MKT under the symbol "ITI." The following table sets forth, for the periods indicated, the
+highest and lowest sales prices for our common stock as reported by NYSE MKT: 
+High 
+Low 
+Fiscal 2014 
+Quarter Ended June 30, 2013 
+$ 
+1.84 
+$ 
+1.55 
+Quarter Ended September 30, 2013 
+1.85 
+1.70 
+Quarter Ended December 31, 2013 
+2.29 
+1.76 
+Quarter Ended March 31, 2014 
+2.50 
+1.92 
+Fiscal 2013 
+Quarter Ended June 30, 2012 
+$ 
+1.52 
+$ 
+1.25 
+Quarter Ended September 30, 2012 
+1.72 
+1.34 
+Quarter Ended December 31, 2012 
+1.82 
+1.45 
+Quarter Ended March 31, 2013 
+1.91 
+1.55 
+On
+August 27, 2014, the last reported sales price of our common stock on the NYSE MKT was $1.72. As of August 27, 2014, we had 383 holders of record of our common stock
+according to information furnished by our transfer agent. 
+Dividend Policy 
+We have never paid or declared cash dividends on our common stock, and have no current plans to pay such dividends in the foreseeable
+future. We currently intend to retain any earnings for working capital and general corporate purposes. The payment of any future dividends will be at the discretion of our Board of Directors and will
+depend upon a number of factors, including, but not limited to, future earnings, the success of our business, our capital requirements, our general financial condition and future prospects, general
+business conditions, the consent of our lender and such other factors as the Board of Directors may deem relevant. 
+Issuer Purchases of Equity Securities 
+In August 2011, our Board of Directors approved a stock repurchase program pursuant to which we were authorized to acquire up to
+$3 million of our outstanding common stock from time to time through August 2012. On August 9, 2012, our Board of Directors approved a new stock repurchase program pursuant to which we
+may acquire up to $3 million of our outstanding common stock for an unspecified length of time. Under the new program, we may repurchase shares from time to time in open-market and privately
+negotiated transactions and block trades, and may also repurchase shares pursuant to an existing or future 10b5-1 trading plan to facilitate repurchases during our closed trading windows. There is no
+guarantee as to the exact number of shares that will be repurchased. We may modify or terminate the repurchase program at any time without prior notice. We did not repurchase any of our common stock
+during the fourth quarter of Fiscal 2014. As of March 31, 2014, we had approximately $747,000 remaining under the repurchase program and all repurchased
+shares have been retired and resumed their status as authorized and unissued shares of our common stock. 
+21 
+Table of Contents 
+ITEM 6. SELECTED FINANCIAL DATA 
+As a smaller reporting company, we are not required to make any disclosure pursuant to this Item 6. 
+ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+You should read the following discussion and analysis in conjunction with our Consolidated Financial Statements
+and related Notes thereto included in Part IV, Item 15 of this report and the "Risk Factors" section in Item 1A, as well as other cautionary statements and risks described
+elsewhere in this report, before deciding to purchase, hold or sell our common stock. 
+Overview 
+General. We are a leading provider of intelligent information solutions for the traffic management market. We are focused on the
+development and
+application of advanced technologies and software-based information systems that reduce traffic congestion, provide measurement, management and predictive traffic analytics and improve the safety of
+surface transportation systems infrastructure. We also believe our products, services and solutions, in conjunction with sound traffic management,
+minimize the environmental impact of traffic congestion. By combining our unique intellectual property, products, decades of experience in traffic management, hyper-local weather solutions and
+information technologies, we offer a broad range of ITS solutions to customers throughout the U.S. and internationally. 
+Acquisitions. In November 2011, we acquired all of the outstanding capital stock of Berkeley Transportation Systems, Inc.
+("BTS"), a
+privately-held company based in Berkeley, California which specializes in transportation performance measurement, for an initial cash payment of approximately $840,000. In the quarter ended
+December 31, 2012, we entered into an amendment to the BTS stock purchase agreement which modified certain earn-out provisions and as a result, we paid an additional $700,000 in cash to the BTS
+shareholders for achievement of those modified earn-out provisions in the fourth quarter of Fiscal 2013. The amendment did not have a material impact on previous estimated amounts accrued in
+connection with the earn-out provisions. This payment completed our obligation under the earn-out provisions of the agreement. During the third quarter of Fiscal 2014, we paid $250,000 pursuant to
+certain holdback provisions. Additionally, we are scheduled to pay to the BTS shareholders up to approximately $335,000 by November 2014 pursuant to certain deferred payment provisions. 
+In
+January 2011, we acquired all of the outstanding capital stock of Meridian Environmental Technology, Inc. ("MET") for an initial cash payment of approximately
+$1.6 million. MET specializes in 511/ advanced traveler information systems and offers ClearPath Weather (formerly, Maintenance Decision Support System or MDSS) management tools that allow
+users to create solutions to meet roadway maintenance decision needs. We also agreed to pay up to $1 million on each of the first two anniversaries of the closing of the acquisition upon the
+satisfaction of certain conditions, as well as up to an additional $2 million under a 24-month earn-out provision. 
+In
+January 2012, we made a cash payment of approximately $668,000 of the first deferred payment to the shareholders of MET and held back $250,000 in accordance with certain provisions of
+the purchase agreement. In June 2012, we determined the contingencies related to the release of the $250,000 holdback were not met. As a result, no portion of the $250,000 holdback was released and
+the entire amount was reversed into operating income during the second quarter of Fiscal 2013. Additionally, no amounts were earned by the MET shareholders related to the first and second year
+earn-out provisions, which ended on December 31, 2011 and 2012, respectively. The second deferred payment of $1 million was due in the fourth quarter of Fiscal 2013. As a result of
+certain holdback 
+22 
+Table of Contents 
+provisions
+and other deductions, the Company paid approximately $409,000 to the MET shareholders in the second quarter of Fiscal 2014. This payment completed the Company's obligation under the
+deferred payment provisions of the purchase agreement. 
+Refer
+to Note 4 of Notes to Consolidated Financial Statements, included in Part IV, Item 15 of this report, for additional discussion on these acquisitions. 
+Sale of Vehicle Sensors. On July 29, 2011, we completed the sale of substantially all of our assets used in connection with
+our Vehicle
+Sensors segment to Bendix Commercial Vehicle Systems LLC ("Bendix"), a member of Knorr-Bremse Group, pursuant to an Asset Purchase Agreement signed on July 25, 2011 (the "Asset Sale").
+Upon closing, Bendix paid us $14 million in cash, subject to a $2 million holdback and adjustments based upon the working capital of the Vehicle Sensors segment at closing, and Bendix
+assumed certain specified obligations and liabilities of the Vehicle Sensors segment. In October 2012, we received approximately $1.7 million in connection with the holdback provision.
+Furthermore, we are entitled to additional consideration in the form of certain performance and royalty-related earn-outs through December 31, 2017. As of March 31, 2014, we have
+received approximately $1.1 million in connection with royalty-related earn-out provisions for a total of $14.8 million in cash from the Asset Sale. As a result of the Asset Sale, we no
+longer operate in the Vehicle Sensors segment, and we determined that the Vehicle Sensors segment, which previously constituted one of our operating segments, qualified as a discontinued operation.
+The applicable financial results of the Vehicle Sensors segment through the closing of the Asset Sale have been reported as a discontinued operation for all periods presented. Refer to Note 3
+of Notes to Consolidated Financial Statements, included in Part IV, Item 15 of this report, for additional discussion on this transaction. 
+Business Segments. Subsequent to the Asset Sale and our acquisition of BTS, we now operate in three reportable segments: Roadway
+Sensors,
+Transportation Systems and iPerform. 
+Roadway Sensors 
+The Roadway Sensors segment includes, among other products, our Vantage, VantageNext, VersiCam, Vantage Vector, SmartCycle, SmartSpan,
+P10, P100 and Abacus vehicle detection systems for traffic intersection control, incident detection and certain highway traffic data collection applications. 
+Transportation Systems 
+The Transportation Systems segment includes transportation engineering and consulting services, and the development of transportation
+management and traveler information systems for the ITS industry. During Fiscal 2012 and Fiscal 2013, this segment included the operations of MET, which specializes in 511/ advanced traveler
+information systems and offers predictive weather and ClearPath Weather management tools that allow users to create solutions to meet roadway maintenance decision needs. As of April 1, 2013,
+the predictive weather and ClearPath Weather services were reassigned to the iPerform segment to better align our predictive weather and traffic capabilities, resources and initiatives. 
+iPerform 
+The iPerform segment includes our performance measurement and information management solutions, including all the operations of BTS,
+which specializes in transportation performance measurement, as well as the predictive weather and ClearPath Weather services reassigned from the Transportation Systems segment on April 1,
+2013. During Fiscal 2012, we began the development of iPeMS. iPeMS is a state-of-the-art, information management software suite that utilizes a wide range of data resources and analytical techniques
+to determine current and future traffic patterns, permitting the effective performance analysis and management of traffic infrastructure resources. This information can 
+23 
+Table of Contents 
+then
+be analyzed by traffic professionals to measure how a transportation network is performing and to identify potential areas of improvement. iPeMS is also capable of providing users with predictive
+traffic analytics and easy-to-use visualization and animation features based on historical traffic conditions. 
+Business Outlook. Given the current ongoing uncertainties regarding global economic conditions, we continue to remain cautious
+about our overall
+business. We believe the economic slowdown, reduction and delay in government funding for transportation infrastructure projects and initiatives, decreased financial capital for our customers, and
+decline in real estate development have negatively affected, and may continue to negatively affect, our financial results for the foreseeable future, and may impair our ability to accurately forecast
+our future financial performance and other business trends. In addition,
+since the end users of a majority of our products and services are governmental entities, we have been, and may continue to be, negatively affected by delays in the passage of a new federal highway
+bill (or the extension of the existing bill) and budgetary issues and delays in purchasing decisions that many municipalities and other state and local agencies continue to face. Spending for new
+roadways, new systems to address traffic congestion and other transportation infrastructure improvements has been delayed or eliminated in some instances. However, we believe the need to rebuild and
+modernize aging transportation infrastructure will continue, and in addition to funds available through the federal highway bill, there exist various other funding mechanisms that support
+transportation infrastructure and related projects. These include bonds, dedicated sales and gas tax measures and other alternative funding sources. 
+Critical Accounting Policies and Estimates 
+"Management's Discussion and Analysis of Financial Condition and Results of Operations" is based on our consolidated financial
+statements included herein, which have been prepared in accordance with accounting principles generally accepted in the United States ("GAAP"). The preparation of these financial statements requires
+management to make estimates and assumptions that affect the reported amounts of assets and liabilities and related disclosures of contingent assets and liabilities at the date of the financial
+statements and the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, we evaluate these estimates and assumptions, including those related to the
+collectability of accounts receivable, the valuation of inventories, the recoverability of long-lived assets and goodwill, the realizability of deferred tax assets, accounting for stock-based
+compensation, the valuation of equity instruments, the valuation of contingent acquisition consideration, warranty reserves and other contingencies. We base these estimates on historical experience
+and on various other factors that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that
+are not readily apparent from other sources. These estimates and assumptions by their nature involve risks and uncertainties, and may prove to be inaccurate. In the event that any of our estimates or
+assumptions are inaccurate in any material respect, it could have a material adverse effect on our reported amounts of assets and liabilities at the date of the financial statements and the reported
+amounts of revenues and expenses during the reporting period. 
+The
+following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. 
+Revenue Recognition. Product revenues and related costs of sales are recognized when all of the following criteria are met:
+(i) persuasive
+evidence of an arrangement exists, (ii) delivery under the terms of the arrangement has occurred, (iii) the price to the customer is fixed or determinable, and (iv) collection of
+the receivable is reasonably assured. These criteria are typically met at the time of product shipment, but in certain circumstances, may not be met until receipt or acceptance by the customer.
+Accordingly, at the date revenue is recognized, the significant obligations or uncertainties concerning the sale have been resolved. 
+24 
+Table of Contents 
+Transportation
+Systems and iPerform revenues are derived primarily from long-term contracts with governmental agencies. When appropriate, revenues are recognized using the percentage of
+completion method of accounting, whereby revenue is recognized as contract performance progresses and is determined based on the relationship of costs incurred to total estimated costs. Any
+anticipated losses on contracts are charged to earnings when identified. Changes in job performance and estimated profitability, including those arising from contract penalty provisions and final
+contract settlements, may result in revisions to costs and revenues and are recognized in the period in which the revisions are determined. Profit incentives are included in revenues when their
+realization is reasonably assured. Certain of our revenues are recognized as services are performed and amounts are earned, which is measured by time incurred or other contractual milestones or output
+measures. Revenues accounted for in this manner generally relate to certain fixed fee professional services, cost-plus fixed fee or time-and-materials contracts. Revenues for ongoing operations and
+maintenance services contracts are generally accounted for ratably as the services are performed throughout the term of the contract. Payments received in advance of services performed are deferred
+and recognized when the related services are performed. 
+We
+recognize revenue from the sale of deliverables that are part of a multiple-element arrangement in accordance with applicable accounting guidance that establishes a relative selling
+price hierarchy permitting the use of an estimated selling price to determine the allocation of arrangement consideration to a deliverable in a multiple-element arrangement where neither vendor
+specific objective evidence ("VSOE") nor third-party evidence ("TPE") of fair value is available for that deliverable. In the absence of VSOE or TPE of the standalone selling price for one or more
+delivered or undelivered elements in a multiple-element arrangement, we are required to estimate the selling prices of those elements. Overall arrangement consideration is allocated to each element
+(both delivered and undelivered items) that has stand-alone value based on their relative selling prices, regardless of whether those selling prices are evidenced by VSOE or TPE or are based on our
+estimated selling prices. 
+We
+account for multiple-element arrangements that consist only of software and software-related services in accordance with applicable accounting guidance for software and
+software-related transactions. For such transactions, revenue on arrangements that include multiple elements is allocated to each element based on the relative fair value of each element, and fair
+value is determined by VSOE. If we cannot objectively determine the fair value of any undelivered element included in such multiple-element arrangements and the only undelivered element is
+post-contract customer support or maintenance, and VSOE of the fair value of such support or maintenance does not exist, revenue from the entire arrangement is recognized ratably over the support
+period. When the fair value of a delivered element has not been established but VSOE of fair value exists for the undelivered elements, we use the residual method to recognize revenue if the fair
+value of all undelivered elements is determinable. Under the residual method, the fair value of the undelivered elements is deferred and the remaining portion of the arrangement fee is allocated to
+the delivered elements and is recognized as revenue. 
+Accounts Receivable. The collectability of our accounts receivable is evaluated through review of outstanding invoices and
+ongoing credit evaluations
+of our customers' financial condition. We record an allowance for doubtful accounts for specific receivables deemed to be at risk for collection as well as a general allowance based on our historical
+collections experience. Considerable judgment is required in assessing and estimating the ultimate realization of trade receivables, including the current credit-worthiness of each customer. If the
+financial condition of our customers deteriorates, resulting in an impairment of their ability to make required payments, additional allowances may be required that could adversely affect our
+operating results. 
+Inventories. Inventories consist of finished goods, work-in-process and raw materials and are stated at the lower of cost or
+market. We write down
+the carrying value of our inventories to net 
+25 
+Table of Contents 
+realizable
+value for estimated excess and obsolete inventories in an amount equal to the difference between the cost of the inventories and their estimated realizable value. These estimates are based
+on management's judgments and assumptions as to future demand requirements and our evaluation of market conditions. Demand for our products may fluctuate significantly over time, and actual demand and
+market conditions may be more or less favorable than those projected by management. In the event that actual demand is lower than originally projected, additional inventory write-downs may be
+required. Estimated inventory write-downs, once established, are not reversed until the related inventory has been sold or scrapped, so if actual market conditions are more favorable in the fiscal
+periods subsequent to those in which we record significant write-downs, we may have higher gross margins when products are sold. 
+Goodwill and Other Long-Lived Assets. Goodwill is recorded as the difference, if any, between the aggregate consideration paid
+for an acquisition and
+the fair value of the acquired net tangible and intangible assets. Other long-lived assets primarily represent purchased intangible assets including developed technology, customer relationships, trade
+names and patents. We currently amortize our intangible assets with definitive lives over periods ranging from one to seven years using a method that reflects the pattern in which the economic
+benefits of the intangible asset are consumed or otherwise used or, if that pattern cannot be reliably determined, using a straight-line amortization method over the estimated useful life of the
+asset. 
+We
+evaluate goodwill on an annual basis in our fourth fiscal quarter or more frequently if we believe indicators of impairment exist. We have determined that our reporting units for
+purposes of testing for goodwill impairment are identical to our reportable segments for financial reporting purposes. In Fiscal 2012, we early adopted the provisions issued by the Financial
+Accounting Standard Board ("FASB") that were intended to simplify goodwill impairment testing. This guidance permits us to first assess qualitative factors to determine whether it is more likely than
+not that the fair value of a reporting unit is less than its carrying amount. If we conclude that it is more likely than not that the fair value of a reporting unit is less than its carrying amount,
+we conduct a two-step goodwill impairment test. The first step of the impairment test involves comparing the fair values of the applicable reporting units with their carrying values. We determine the
+fair values of our reporting units using the income valuation approach, as well as other generally accepted valuation methodologies. If the carrying amount of a reporting unit exceeds the reporting
+unit's fair value, we perform the second step of the goodwill impairment test. The second step of the goodwill impairment test involves comparing the implied fair value of the affected reporting
+unit's goodwill with the carrying value of that goodwill. The amount by which the carrying value of the goodwill exceeds its implied fair value, if any, is recognized as an impairment loss. We monitor
+the indicators for goodwill impairment testing between annual tests. Certain adverse business conditions impacting one or more reporting units would cause us to test goodwill for impairment on an
+interim basis. As part of our annual assessment, management determines the most appropriate and efficient method to assess goodwill for impairment, which could include either the simplified testing
+approach or the two-step goodwill test described above. 
+We
+test long-lived assets and purchased intangible assets (other than goodwill) for impairment if we believe indicators of impairment exist. We determine whether the carrying value of an
+asset or asset group is recoverable, based on comparisons to undiscounted expected future cash flows the asset are expected to generate. If an asset is not recoverable, we record an impairment loss
+equal to the amount by which the carrying value of the asset exceeds its fair value. We primarily use the income valuation approach to determine the fair value of our long lived assets and purchased
+intangible assets. 
+Warranty. We generally provide a one to three year warranty from the original invoice date on our products, materials and
+workmanship. Products sold
+to various original equipment manufacturer customers sometimes carry longer warranties. Defective products will be either repaired or replaced, usually at our option, upon meeting certain criteria. We
+accrue a provision for the estimated costs that 
+26 
+Table of Contents 
+may
+be incurred for product warranties relating to a product as a component of cost of sales at the time revenue for that product is recognized. The accrued warranty reserve is included within accrued
+liabilities in the accompanying consolidated balance sheets. Should our actual experience of warranty returns be higher than anticipated, additional warranty reserves may be required, which would
+adversely affect our product gross profit and our operating results. 
+Income Taxes. We utilize the asset and liability method of accounting for income taxes, under which deferred taxes are
+determined based on the
+temporary differences between the financial statement and tax basis of assets and liabilities using tax rates expected to be in effect during the years in which the basis differences reverse. A
+valuation allowance is recorded when it is more-likely-than-not that some or all of the deferred tax assets will not be realized, which increases our income tax expense in the period such
+determination is made. 
+On
+an interim basis, we estimate what our anticipated annual effective tax rate will be, while also separately considering applicable discrete and other non-recurring items, and record a
+quarterly income tax provision in accordance with this anticipated rate. As the fiscal year progresses, we refine our estimates based upon actual events and financial results during the year. This
+estimation process can result in significant changes to our expected effective tax rate. When this occurs, we adjust our income tax provision during the quarter in which our estimates are refined so
+that the year-to-date provision reflects the expected annual effective tax rate. These changes, along with adjustments to our deferred taxes, among others, may create fluctuations in our overall
+effective tax rate from quarter to quarter. 
+Income
+tax positions must meet a more-likely-than-not recognition threshold to be recognized. Income tax positions that previously failed to meet the more-likely-than-not threshold are
+recognized in the first subsequent financial reporting period in which that threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not threshold are reversed in
+the first subsequent financial reporting period in which that threshold is no longer met. 
+The
+application of tax laws and regulations is subject to legal and factual interpretation, judgment and uncertainty. Tax laws and regulations themselves are subject to change as a
+result of changes in fiscal policy, changes in legislation, the evolution of regulations and court rulings. Therefore, the actual liability for U.S. or foreign taxes may be materially different from
+our estimates, which could result in the need to record additional tax liabilities or potentially reverse previously recorded tax liabilities. 
+Stock-Based Compensation. We record stock-based compensation in the statements of operations as an expense, based on the
+estimated grant date fair
+value of our stock-based awards, whereby such fair values are amortized over the requisite service period. Our stock-based awards are currently comprised of common stock options and restricted stock
+units. The fair value of our stock option awards is estimated on the grant date using the Black-Scholes-Merton ("BSM") option-pricing formula. While utilizing this model meets established
+requirements, the estimated fair values generated by it may not be indicative of the actual fair values of our stock option awards as it does not consider certain factors important to those awards to
+employees, such as continued employment and periodic vesting requirements as well as limited transferability. The fair value of our restricted stock units is based on the closing market price of our
+common stock on the grant date. If there are any modifications or cancellations of the underlying unvested stock-based awards, we may be required to accelerate, increase or cancel any remaining
+unearned stock-based compensation expense. 
+Recent Accounting Pronouncements 
+Refer to Note 1 of Notes to Consolidated Financial Statements, included in Part IV, Item 15 of this report, for a
+discussion of recent accounting pronouncements. 
+27 
+Table of Contents 
+Results of Operations 
+The following table sets forth certain statement of operations data as a percentage of revenues for the periods indicated. 
+Year Ended March 31, 
+2014 
+2013 
+2012 
+Total revenues 
+100.0 
+% 
+100.0 
+% 
+100.0 
+% 
+Cost of revenues 
+61.9 
+62.3 
+60.5 
+Gross profit 
+38.1 
+% 
+37.7 
+% 
+39.5 
+% 
+Operating expenses: 
+Selling, general and administrative 
+28.3 
+29.3 
+30.8 
+Research and development 
+5.9 
+5.0 
+5.4 
+Amortization of intangible assets 
+0.9 
+1.0 
+0.9 
+Change in fair value of contingent consideration 
+0.0 
+(0.3 
+) 
+(1.1 
+) 
+Impairment of goodwill 
+— 
+— 
+— 
+Total operating expenses 
+35.1 
+35.0 
+36.0 
+Operating income 
+3.0 
+2.7 
+3.5 
+Non-operating income (expense): 
+Other income (expense), net 
+— 
+0.0 
+0.0 
+Interest income (expense), net 
+— 
+(0.0 
+) 
+(0.1 
+) 
+Income from continuing operations before income taxes 
+3.0 
+2.7 
+3.4 
+Provision for income taxes 
+(1.0 
+) 
+(1.2 
+) 
+(1.1 
+) 
+Income from continuing operations 
+2.0 
+1.5 
+2.3 
+Gain on sale of discontinued operation, net of tax 
+0.1 
+2.4 
+2.0 
+Net income 
+2.1 
+% 
+3.9 
+% 
+4.3 
+% 
+Analysis of Fiscal 2014, Fiscal 2013 and Fiscal 2012 Results of Operations 
+Total Revenues. Total revenues are comprised of sales from our Roadway Sensors, Transportation Systems and iPerform segments.
+The
+following tables present details of total revenues for Fiscal 2014 compared to Fiscal 2013, and Fiscal 2013 compared to Fiscal 2012: 
+Year Ended 
+March 31, 
+% 
+Change 
+2014 
+2013 
+Increase 
+(In thousands, except percentages) 
+Total revenues 
+$ 
+68,228 
+$ 
+61,685 
+$ 
+6,543 
+10.6 
+% 
+Year Ended 
+March 31, 
+% 
+Change 
+2013 
+2012 
+Increase 
+(in thousands, except percentages) 
+Total revenues 
+$ 
+61,685 
+$ 
+58,406 
+$ 
+3,279 
+5.6 
+% 
+We
+currently have, and historically have had, a diverse customer base. For Fiscal 2014, one individual customer represented approximately 11% of our total revenues and no other
+individual customer represented greater than 10% of our total revenues. For Fiscal 2013, one individual customer represented approximately 13% of our total revenues and no other individual customer
+represented 
+28 
+Table of Contents 
+greater
+than 10% of our total revenues. For Fiscal 2012, no individual customer represented greater than 10% of our total revenues. 
+Total
+revenues for Fiscal 2014 increased approximately 10.6% to $68.2 million, compared to $61.7 million in Fiscal 2013, due primarily to an increase of approximately 22.2%
+in Roadway Sensors revenues, approximately 1.7% in Transportation Systems and approximately 4.6% in iPerform. 
+Total
+revenues for Fiscal 2013 increased approximately 5.6% to $61.7 million, compared to $58.4 million in Fiscal 2012, due primarily to an increase of approximately 8.7%
+in Transportation Systems revenues and an increase in iPerform revenues of approximately $2.4 million, which was attributable to a full twelve months of revenues in Fiscal 2013 from the
+acquisition of BTS in November 2011. These increases in revenue were partially offset by an approximate 6.1% decrease in Roadway Sensors revenues. 
+Roadway
+Sensors revenues in Fiscal 2014 increased approximately 22.2% compared to Fiscal 2013, primarily due to the success of various growth initiatives we developed earlier in the
+year, including increases in the Company's international sales and increases in unit sales of certain original equipment manufacturer ("OEM") products. Roadway Sensors revenues in Fiscal 2013
+decreased approximately 6.1% compared to Fiscal 2012, due mainly as a result of a decrease in federal stimulus funded projects and as a result of the discontinuation of redevelopment agencies in
+California. The federal stimulus funded projects and redevelopment agencies in California had a positive impact on Roadway Sensors revenues in the prior year periods. Going forward, we plan to focus
+on our core domestic intersection market and refine and deliver products that address the needs of this market, namely our Vantage processor and camera systems and our Vantage Vector video/radar
+hybrid sensor, as well as our newly released SmartCycle, SmartSpan and VantageNext products. Additionally, we plan to focus on international distribution channel expansion and expect to continue to
+refine products that address these markets, namely our Abacus, P10 and P100 (formerly, Pico) products. 
+Transportation
+Systems revenues in Fiscal 2014 increased approximately 1.7% compared to Fiscal 2013, primarily as a result of timing of backlog fulfillment on certain projects. Revenues
+from our Transportation Systems segment are primarily dependent upon the continued availability of funding at the local, state and federal levels from the various agencies and departments of
+transportation. Transportation Systems revenues for Fiscal 2013 increased approximately 8.7% compared to Fiscal 2012 due in part to several significant project wins in the first two quarters of Fiscal
+2013. Going forward, we plan to continue to pursue larger contracts that may contain significant sub-consulting content, which will likely contribute to variability in the timing and amount of our
+Transportation Systems revenues from period to period. We also intend to continue to expand our foreign operations by pursuing additional international opportunities in the Middle East and other
+regions. Among other factors, we believe the ability of our Transportation Systems segment to grow and successfully win and service new contracts will be highly dependent upon our continued success in
+recruiting and retaining qualified personnel, as well as the continued availability of funding at the local, state and federal levels from the various agencies and departments of transportation. 
+iPerform
+revenues in Fiscal 2014 increased approximately 4.6% compared to Fiscal 2013, primarily attributable to additional contract awards with certain public agencies. Approximately
+$3.3 million of the total revenues in Fiscal 2013 and approximately $935,000 of the total revenues in Fiscal 2012 were attributable to the iPerform segment and was a direct result of the BTS
+acquisition in November 2011. Going forward, we plan to continue investing in this segment, particularly in research, development, sales and marketing of the iPeMS performance measurement and
+ClearPath Weather solutions, with a near-term focus on delivering iPeMS to public agencies. We also plan for iPerform to pursue commercial opportunities in our ClearPath Weather and ClearPath
+Agriculture solutions. 
+29 
+Table of Contents 
+Gross Profit. The following tables present details of our gross profit for Fiscal 2014 compared to Fiscal 2013, and Fiscal 2013
+compared to Fiscal
+2012: 
+Year Ended March 31, 
+% 
+Change 
+2014 
+2013 
+Increase 
+(In thousands, except percentages) 
+Gross profit 
+$ 
+25,974 
+$ 
+23,258 
+$ 
+2,716 
+11.7 
+% 
+Gross profit as a % of total revenues 
+38.1 
+% 
+37.7 
+% 
+Year Ended March 31, 
+% 
+Change 
+2013 
+2012 
+Increase 
+(in thousands, except percentages) 
+Gross profit 
+$ 
+23,258 
+$ 
+23,071 
+$ 
+187 
+0.8 
+% 
+Gross profit as a % of total revenues 
+37.7 
+% 
+39.5 
+% 
+Our
+total gross profit as a percentage of total revenues for Fiscal 2014 increased approximately 0.4% compared to Fiscal 2013 primarily as a result of our product and service mix.
+Revenues derived from our Roadway Sensors segment increased to approximately 46.6% of our total revenues in Fiscal 2014 as compared to approximately 42.2% in Fiscal 2013. Roadway Sensors revenues
+carry higher gross margins than Transportation Systems and iPerform revenues. Therefore, the increase in Roadway Sensors revenues had a positive impact on our overall margin. 
+Our
+total gross profit as a percentage of total revenues for Fiscal 2013 decreased approximately 1.8% compared to Fiscal 2012 primarily as a result of our product and service mix.
+Revenues derived from our Roadway Sensors segment decreased to approximately 42.2% of our total revenues in Fiscal 2013 as compared to 47.4% in Fiscal 2012. Gross profits as a percentage of total
+revenues also declined, to a lesser extent, as a result of an approximate 2.7% decrease in Roadway Sensors profit margins due to the overall decrease in revenues and an increase in sustaining
+engineering activities. 
+Roadway
+Sensors gross profit can fluctuate in any specific quarter or year based on, among other factors, customer and product mix, competitive pricing requirements, product warranty
+costs and provisions for excess and obsolete inventories, as well as shifts of engineering resources from development activities to sustaining activities, which we record as cost of goods sold. 
+We
+recognize a portion of our Transportation Systems and iPerform revenues and related gross profit using percentage of completion contract accounting and the underlying mix of contract
+activity affects the related gross profit recognized in any given period. For the Transportation Systems segment, we expect to experience gross profit variability in future periods due to our contract
+mix and related sub-consulting content of such contracts, as well as factors such as our ability to efficiently utilize our workforce, which could cause fluctuations in our margins from period to
+period. 
+30 
+Table of Contents 
+Selling, General and Administrative Expense 
+The following table presents selling, general and administrative expense for Fiscal 2014 and Fiscal 2013: 
+Year Ended March 31, 
+2014 
+2013 
+Amount 
+% of 
+Revenues 
+Amount 
+% of 
+Revenues 
+Increase 
+(Decrease) 
+% 
+Change 
+(In thousands, except percentages) 
+Salary and personnel-related 
+$ 
+12,955 
+19.0 
+% 
+$ 
+12,223 
+19.8 
+% 
+$ 
+732 
+6.0 
+% 
+Facilities, insurance and supplies 
+2,603 
+3.8 
+2,255 
+3.7 
+348 
+15.4 
+Travel and conferences 
+1,502 
+2.2 
+1,281 
+2.1 
+221 
+17.3 
+Professional and outside services 
+1,593 
+2.3 
+1,964 
+3.2 
+(371 
+) 
+(18.9 
+) 
+Other 
+616 
+0.9 
+367 
+0.6 
+249 
+67.8 
+Selling, general and administrative 
+$ 
+19,269 
+28.2 
+% 
+$ 
+18,090 
+29.3 
+% 
+$ 
+1,179 
+6.5 
+The
+overall increase in selling, general and administrative expense for Fiscal 2014, as compared to Fiscal 2013, was primarily due to planned investments in Roadway Sensors and iPerform
+sales and marketing, including increased headcount which resulted in higher salary and personnel-related costs and travel. The overall increase was also attributable to business travel, facility
+related costs, supplies and other miscellaneous expenses. 
+We
+anticipate that our selling, general and administrative expense for the first half of Fiscal 2015 will be significantly higher than the corresponding period in Fiscal 2014 as a result
+of the additional costs incurred in connection with the audit of our Fiscal 2014 financial statements. In addition, we expect that we will have additional recurring costs in future periods for
+improvements to our internal control design and the related augmentation of resources. 
+The
+following table presents selling, general and administrative expense for Fiscal 2013 and 2012: 
+Year Ended March 31, 
+2013 
+2012 
+Amount 
+% of 
+Revenues 
+Amount 
+% of 
+Revenues 
+Increase 
+(Decrease) 
+% 
+Change 
+(In thousands, except percentages) 
+Salary and personnel-related 
+$ 
+12,223 
+19.8 
+% 
+$ 
+12,434 
+21.3 
+% 
+$ 
+(211 
+) 
+(1.7 
+)% 
+Facilities, insurance and supplies 
+2,255 
+3.7 
+1,853 
+3.2 
+402 
+21.7 
+Travel and conferences 
+1,281 
+2.1 
+1,568 
+2.7 
+(287 
+) 
+(18.3 
+) 
+Professional and outside services 
+1,964 
+3.2 
+1,778 
+3.0 
+186 
+10.5 
+Other 
+367 
+0.6 
+353 
+0.6 
+14 
+4.0 
+Selling, general and administrative 
+$ 
+18,090 
+29.3 
+% 
+$ 
+17,986 
+30.8 
+% 
+$ 
+104 
+0.6 
+Selling,
+general and administrative expenses for Fiscal 2013 were generally consistent, in total, with those in Fiscal 2012. The increase in facilities and insurance costs was due to the
+increased cost of rent, rent related expenses and insurance coverage for a full twelve month period for our Berkeley, California office, related to the operations of BTS, which was acquired in
+November 2011. This increase was partially offset by a decrease in travel expenses, as well a decrease in general salary and personnel-related expenses. 
+31 
+Table of Contents 
+Research and Development Expense 
+The following table presents research and development expense for Fiscal 2014 and Fiscal 2013: 
+Year Ended March 31, 
+2014 
+2013 
+Amount 
+% of 
+Revenues 
+Amount 
+% of 
+Revenues 
+Increase 
+(Decrease) 
+% 
+Change 
+(In thousands, except percentages) 
+Salary and personnel-related 
+$ 
+2,314 
+3.4 
+% 
+$ 
+1,454 
+2.4 
+% 
+$ 
+860 
+59.1 
+% 
+Facilities, development and supplies 
+1,232 
+1.8 
+1,378 
+2.2 
+(146 
+) 
+(10.6 
+) 
+Other 
+483 
+0.7 
+239 
+0.4 
+244 
+102.1 
+Research and development 
+$ 
+4,029 
+5.9 
+% 
+$ 
+3,071 
+5.0 
+% 
+$ 
+958 
+31.2 
+Research
+and development expense for Fiscal 2014 increased approximately 31.2% compared to Fiscal 2013, primarily due to increased salary and personnel costs related to certain planned
+expenditures for software development in the iPerform segment, including increased headcount, as well as investments in securing intellectual property rights. 
+The
+iPerform segment continued to develop an improved version of their flagship traffic analytics product, iPeMS. We anticipate this new offering will allow customers to seamlessly
+ingest traffic data from leading data providers, providing "plug-and-play" data capabilities and reduce the need for custom integration. As of March 31, 2014, we have capitalized approximately
+$500,000 of iPeMS software development included in intangible assets in the consolidated balance sheet. We began amortizing these assets into costs of revenues in the consolidated statement of
+operations in the third quarter of Fiscal 2014. 
+Going
+forward, iPerform expects to continue developing and upgrading its performance management solution suite, including iPeMS, ClearPath Weather and ClearPath Agriculture, which will
+require additional investments. 
+The
+following table presents research and development expense for Fiscal 2013 and Fiscal 2012: 
+Year Ended March 31, 
+2013 
+2012 
+Amount 
+% of 
+Revenues 
+Amount 
+% of 
+Revenues 
+Increase 
+(Decrease) 
+% 
+Change 
+(In thousands, except percentages) 
+Salary and personnel-related 
+$ 
+1,454 
+2.4 
+% 
+$ 
+2,153 
+3.7 
+% 
+$ 
+(699 
+) 
+(32.5 
+)% 
+Facilities, development and supplies 
+1,378 
+2.2 
+792 
+1.4 
+586 
+74.0 
+Other 
+239 
+0.4 
+238 
+0.4 
+1 
+0.4 
+Research and development 
+$ 
+3,071 
+5.0 
+% 
+$ 
+3,183 
+5.4 
+% 
+$ 
+(112 
+) 
+(3.5 
+) 
+Research
+and development expense in Fiscal 2013 decreased approximately 3.5% when compared to Fiscal 2012, primarily due to certain expenditures related to software development in the
+iPeform segment that were capitalized to the balance sheet as of March 31, 2013, as well as certain reductions to Roadway Sensors salary and personnel-related expenditures. These reductions
+were offset by an increase in facility rents, development and supplies expense. The increase in facility costs was attributable to a full twelve month period for our Berkeley, California office,
+related to the operations of BTS that were acquired in November 2011. 
+32 
+Table of Contents 
+Impairment of Goodwill 
+In Fiscal 2012, we adopted the provisions issued by the FASB that are intended to simplify goodwill impairment testing. The updated
+guidance permits us to first assess
+qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If we conclude that it is more likely than not that the
+fair value of a reporting unit is less than its carrying amount, we conduct a two-step goodwill impairment test. We performed annual impairment assessments of the carrying value of goodwill for Fiscal
+2014 and Fiscal 2013 in their fourth fiscal quarters, respectively. We determined it was more appropriate and cost effective to perform a qualitative assessment in Fiscal 2012 and a quantitative
+first-step assessment in Fiscal 2013 and Fiscal 2014 to estimate the fair value of our reporting units using both the income approach and market approach. Based on our assessments, we determined that
+no impairment was indicated as the estimated fair value of each reporting unit exceeded its respective carrying value. 
+Based
+on our goodwill impairment testing for Fiscal 2012, Fiscal 2013 and Fiscal 2014, we believe the carrying value of our goodwill is not currently impaired, as the estimated fair
+values of our reporting units exceeded their carrying values at March 31, 2014. If our actual financial results, or the plans and estimates used in future goodwill impairment analyses, are
+lower than the original estimates used to assess impairment of our goodwill, we could incur future goodwill impairment charges. 
+Interest Expense, Net 
+Net interest expense was approximately $0, $6,000 and $72,000 in Fiscal 2014, Fiscal 2013 and Fiscal 2012, respectively. The sequential
+decreases were primarily due to a continuous decrease in the overall level of borrowings on our term note. During the first quarter of Fiscal 2013, all principal and interest under the term note were
+paid in full. See "Liquidity and Capital Resources" below for additional details on our borrowings. 
+Income Taxes 
+The following table presents our provision for income taxes for Fiscal 2014, Fiscal 2013 and Fiscal 2012: 
+Year Ended March 31, 
+2014 
+2013 
+2012 
+(In thousands, except 
+percentages) 
+Provision for income taxes 
+$ 
+704 
+$ 
+716 
+$ 
+643 
+Effective tax rate 
+34.8 
+% 
+43.9 
+% 
+33.0 
+% 
+Our
+effective tax rate for Fiscal 2014 was favorably impacted by the recognition of approximately $359,000 of tax credits, partially offset by permanent non-deductible tax items,
+including share-based payments and other permanent differences amounting to approximately $103,000, and by the recording a valuation allowance against certain of our state net operating losses in the
+amount of $185,000, net of federal benefit. 
+Our
+effective tax rate for Fiscal 2013 was unfavorably impacted by permanent non-deductible tax items, including share-based payments and other permanent differences amounting to
+approximately $82,000, and by the recording of a valuation allowance against certain of our state net operating losses in the amount of $188,000, net of federal benefit. These unfavorable impacts were
+partially offset by the
+recognition of tax credits of approximately $122,000 for research and development and hiring activities, and by approximately $62,000 of tax benefit from non-taxable favorable fair value adjustments
+recognized for financial statement purposes. 
+33 
+Table of Contents 
+Our
+effective tax rate for Fiscal 2012 was favorably impacted by the recognition of approximately $276,000 of previously unrecognized tax benefits during Fiscal 2012 due to the
+expiration of statutes limitation in various jurisdictions, by the recognition of tax credits of approximately $246,000 for research and development activities, and by approximately $211,000 of tax
+benefit from non-taxable favorable fair value adjustments recognized for financial statement purposes. These favorable impacts were partially offset by the impact of recognizing approximately $466,000
+of expense upon the expiration of a state net operating loss, net of federal benefit. 
+As
+of March 31, 2014 and 2013, we recorded a valuation allowance against certain of our state net operating loss carryforwards, which we estimated were likely to not be realized
+within the applicable carryforward period in the amount of $373,000 and $188,000, respectively, net of federal tax benefit. In making our determination as to the realizability of our deferred tax
+assets, we reviewed all available positive and negative evidence, including reversal of deferred tax liabilities, potential carrybacks, projected future taxable income, tax planning strategies and
+recent financial performance. 
+As
+we update our estimates in future periods, adjustments to our deferred tax asset and valuation allowance may be necessary. We anticipate this will cause our future overall effective
+tax rate in any given period to fluctuate from prior effective tax rates and statutory tax rates. We utilize the liability method of accounting for income taxes. We record net deferred tax assets to
+the extent that we believe these assets will more likely than not be realized. In making such determination, we consider all available positive and negative evidence, including, but not limited to,
+scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial performance. 
+At
+March 31, 2014, we had $18.6 million of federal net operating loss carryforwards and $8.0 million of state net operating loss carryforwards that begin to expire
+in 2021 and 2015, respectively. Although the impact cannot be precisely determined at this time, we believe that our net operating loss carryforwards will cause us to have future income tax payments
+that are substantially lower than the income tax liability calculated using statutory tax rates. Due to changes in stock ownership, our federal net operating loss carryforwards and other federal
+attributes are subject to a Section 382 annual limitation. 
+Liquidity and Capital Resources 
+Cash Flows 
+We have historically financed our operations with a combination of cash flows from operations, borrowings under credit facilities and
+the sale of equity securities. We currently rely on cash flows from operations and the availability of borrowings on a line of credit facility to fund our operations, which we believe to be sufficient
+to fund our operations for at least the next twelve months. However, we may need or choose to raise additional capital to fund potential future acquisitions and our future growth. We may raise such
+funds by selling equity or debt securities to the public or to selected investors or by borrowing money from financial institutions. If we raise additional funds by issuing equity or convertible debt
+securities, our existing stockholders may experience significant dilution and any equity securities that may be issued may have rights senior to our existing stockholders. 
+At
+March 31, 2014, we had $30.9 million in working capital, which included $20.4 million in cash and cash equivalents and reflected no borrowings on our
+$12.0 million line of credit. This compares to working capital of $29.4 million at March 31, 2013, which included no borrowings on our line of credit and $18.7 million in
+cash and cash equivalents. 
+34 
+Table of Contents 
+The
+following table summarizes our cash flows for Fiscal 2014, Fiscal 2013 and Fiscal 2012: 
+Year Ended March 31, 
+2014 
+2013 
+2012 
+(In thousands) 
+Net cash provided by (used in): 
+Operating activities 
+$ 
+3,274 
+$ 
+3,193 
+$ 
+668 
+Investing activities 
+(779 
+) 
+367 
+10,002 
+Financing activities 
+(759 
+) 
+(3,583 
+) 
+(3,787 
+) 
+Operating Activities. Cash provided by our operations in Fiscal 2014 was primarily the result of our net income of approximately
+$1.4 million
+and approximately $2.6 million non-cash items for depreciation, amortization, stock-based compensation expense and adjustments to deferred tax assets. This was offset by approximately
+$0.7 million used in working capital, consisting of approximately $1.5 million from accounts receivable, inventories, and net costs and estimated earnings in excess of billings, net of
+approximately $0.8 million for prepaid expenses and other assets and accounts payable and accrued activities. 
+Our
+accounts receivable and costs and estimated earnings in excess of billings increased approximately $0.9 million, or 4.9%, during Fiscal 2014 mainly as a result of an
+approximate 11.0% year-over-year increase in revenues. In the near future, our accounts receivable and net costs and estimated earnings in excess of billings accounts are likely to be determined based
+upon, among other factors, increases or decreases in revenues, the timing of collections of existing receivables and our ability to timely invoice our billings in excess of costs. We try to offset
+significant increases in accounts receivables through increased and focused collection efforts; however, we cannot assure you that our collection efforts will be successful. The increase in accounts
+payable by approximately $502,000 at March 31, 2014 compared to March 31, 2013 was largely driven by the general timing of payments to vendors and sub-consultants. 
+Cash
+provided by our operations in Fiscal 2013 was primarily the result of (i) adding back to net income $901,000 of depreciation expense, $279,000 of stock-based compensation
+expense, $644,000 of amortization expense and $1.4 million of deferred tax assets, (ii) deducting from net income $181,000 in changes in the fair value of contingent consideration
+related to our prior acquisitions of MET and BTS and $1.5 million of gain on the sale of Vehicle Sensors and (iii) approximately $300,000 in negative cash flows resulting from changes in
+our operating assets and liabilities during Fiscal 2013, all of which was offset by our net income of $2.4 million for such fiscal year. Our accounts receivable and net costs and estimated
+earnings in excess of billings increased approximately $851,000, or 5.2%, during Fiscal 2013 mainly as a result of an approximate 5.6% year-over-year increase in revenues. 
+Cash
+provided by our operations in Fiscal 2012 was primarily the result of (i) adding back to net income $907,000 of depreciation expense, $331,000 of stock-based compensation
+expense, $504,000 of amortization expense and $286,000 of deferred tax assets, (ii) deducting from net income $619,000 in changes in the fair value of contingent consideration related to our
+acquisitions of MET and BTS and $1.2 million for the gain on the sale of Vehicle Sensors and (iii) $2.1 million in negative cash flows resulting from changes in our operating
+assets and liabilities during Fiscal 2012, all of which was offset by our net income of $2.5 million for such fiscal year. Our accounts receivable and net costs and estimated earnings in excess
+of billings increased approximately $3.0 million, or 21.9%, during Fiscal 2012 mainly as a result of a 12.4% year-over-year increase in net sales and contract revenues as well as the timing of
+collection on certain receivables. 
+Investing Activities. Cash used in our investing activities during Fiscal 2014 consisted of approximately $452,000 for purchases
+of property and
+equipment and approximately $301,000 used for the development of software and data acquisitions in the iPerform segment. Cash provided by our 
+35 
+Table of Contents 
+investing
+activities for Fiscal 2013 primarily consisted of (i) $1.4 million in proceeds from the sale of the Vehicle Sensors segment, (ii) purchases of property and equipment of
+$815,000 and (iii) capitalized software of $190,000 related to iPeMS. Cash provided by our investing activities for Fiscal 2012 largely consisted of (i) $11.4 million in proceeds
+from the sale of the Vehicle Sensors segment, (ii) $1.0 million used for the acquisition of MET and BTS, which consisted of $840,000 for the initial purchase of BTS and $129,000 related
+to purchase price adjustments for the purchase of MET, (iii) purchases of property and equipment of $337,000 and (iv) capitalized software of $138,000 related to iPeMS. 
+Financing Activities. Net cash used in financing activities during Fiscal 2014 was primarily the result of
+approximately $409,000 in cash used for a deferred payment for the prior acquisition of MET, approximately $250,000 in cash used for an earn-out payment for the prior acquisition of BTS, and
+approximately $339,000 in cash used to repurchase shares of our common stock under our stock repurchase program. This was partially offset by our receipt of proceeds of $270,000 from stock option and
+warrant exercises. Net cash used in our financing activities during Fiscal 2013 primarily consisted of $2.5 million used to repurchase our common stock under our stock repurchase program,
+$634,000 in payments on our long-term debt and $700,000 paid to the BTS shareholders for achievement of earn-out provisions of the purchase agreement. Net cash used in our financing activities during
+Fiscal 2012 primarily consisted of $2.3 million in payments on our long-term debt, which consists of a bank term note, $676,000 related to the first year deferred payment to the former
+stockholders of MET, $112,000 for the second anniversary payment for the prior acquisition of BTS and $754,000 used to repurchase our common stock under our stock repurchase program. 
+Borrowings 
+In October 2008, we entered into a $19.5 million credit facility with California Bank & Trust ("CB&T"). This credit
+facility provided for a two-year revolving line of credit with borrowings of up to $12.0 million and a $7.5 million 48-month term note. In September 2010, we entered into a modification
+agreement with CB&T to extend the expiration date of our revolving line of credit to October 1, 2012. We repaid in full all principal and interest payments under the term note in September
+2012; the term note did not contain any early termination fees or prepayment penalties. 
+In
+September 2012, we entered into a second modification agreement with CB&T to extend the expiration date of our revolving line of credit to October 1, 2014. Interest on borrowed
+amounts under the revolving line of credit are payable monthly at a rate equal to the current stated prime rate (3.25% at March 31, 2014) up to the current stated prime rate plus 0.25%,
+depending on aggregate deposit balances maintained at the bank in relation to the total loan commitment under the credit facility. We are obligated to pay an unused line fee of 0.25% per annum applied
+to the average unused portion of the revolving line of credit during the preceding month. The revolving line of credit does not contain early termination fees and is secured by substantially all of
+our assets. 
+As
+of March 31, 2014 and March 31, 2013, no amounts were outstanding under the revolving line of credit. Availability under this line of credit may be reduced or otherwise
+limited as a result of our obligations to comply with certain financial and other covenants. 
+In
+connection with our credit facility and loan agreement with CB&T, we are also required to comply with certain quarterly financial covenants. These include achieving ratios for working
+capital and debt service, as well as maintaining a level of profitability, all of which are further defined in the agreement. As of March 31, 2014, we were in compliance with all such financial
+covenants. We cannot assure you that we will not violate one or more covenants in the future. If we were to be in violation of certain covenants under this agreement, our lender could choose to
+accelerate payment on all outstanding loan balances and pursue its security interest in our assets. In this event, we cannot assure you that we
+would be able to quickly obtain equivalent or suitable replacement financing on acceptable terms, on a timely basis, or at all. If we were not able to secure alternative sources of financing, such
+acceleration could have a material adverse impact on our business and financial condition. 
+36 
+Table of Contents 
+Off-Balance Sheet Arrangements 
+Other than our operating leases, which are further described at Note 9 of Notes to Consolidated Financial Statements, included
+in Part IV, Item 15 of this report, we do not believe we have any other material off-balance sheet arrangements at March 31, 2014. 
+Seasonality 
+We have historically experienced seasonality, particularly with respect to our Roadway Sensors sales in our third and fourth fiscal
+quarters due to a reduction in intersection construction and repairs during the winter months due to inclement weather conditions, with the third fiscal quarter generally impacted the most by
+inclement weather. We have also experienced seasonality, particularly with respect to our Transportation Systems revenues in our third fiscal quarter due to the increased number of holidays, causing a
+reduction in available billable hours. With the addition of MET in January 2011, we have also experienced seasonality related to certain ClearPath Weather
+services in our first and second fiscal quarters mainly because these services are generally not required during spring and summer when weather conditions are comparatively milder. 
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
+Interest Rate Risk 
+Our exposure to interest rate risk is limited to our line of credit, which bears interest equal to the prevailing prime rate (3.25% at
+March 31, 2014) plus 0% to 1.0%. We do not believe that a 10% increase in the interest rate on our line of credit would have a material impact on our financial position, operating results or
+cash flows. 
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+The financial statements and supplementary data required by Regulation S-X are included in Part IV, Item 15 of
+this report. 
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+None. 
+ITEM 9A. CONTROLS AND PROCEDURES 
+(a) Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934, as
+amended
+(the "Exchange Act"), as of the end of the period covered by this Annual Report on Form 10-K, management evaluated, with the participation of our President and Chief Executive Officer and our
+Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act). Based upon their
+evaluation of these disclosure controls and procedures, the President and Chief Executive Officer and the Chief Financial Officer have concluded that our disclosure controls and procedures were not
+effective as of March 31, 2014 because of a material weakness in our internal controls over financial reporting ("ICFR") as described below. 
+(b) Material weakness in ICFR. A material weakness is a deficiency, or combination of deficiencies, in ICFR, such that there is a
+reasonable
+possibility that a material misstatement of the Company's annual or interim financial statements will not be prevented or detected on a timely basis. Management has identified the following
+significant deficiencies that constitute a material weakness in our ICFR as of March 31, 2014: 
+37 
+Table of Contents 
+• The Company has not designed appropriate internal controls to analyze each consulting contract to determine if it should
+be accounted for in accordance with contract accounting (FASB Accounting Standards Codification ("ASC") 605-35, Construction-Type and Production-Type
+Contracts ) or as a multiple element arrangement (ASC 605-25, Revenue Recognition: Multiple-Element Arrangements ) and the proper
+revenue recognition policy to apply. 
+• The Company has not consistently evaluated how an arrangement or a contract should be bifurcated into separate elements
+or how separate elements within such arrangements are properly combined in accordance with GAAP. 
+• The Company has not designed sufficient controls to consider the impact of software elements and if such elements result
+in the arrangement or portions of the arrangement to be software elements to be accounted for in accordance with ASC 985-605, Software: Revenue
+Recognition . 
+(c) Plan for remediation of material weakness. Management is actively engaged in the planning for, and implementation of, remediation
+efforts to
+address the material weakness identified above. Management has or intends to take the following actions to address the material weakness: 
+• Management has created a new position (Director, Revenue Recognition) to perform the proper analysis for multiple element
+contracts, software elements, construction accounting, and other technical accounting issues. 
+• Management began implementing processes and controls during the first quarter of Fiscal 2015 to evaluate multiple
+deliverable arrangements to ensure revenue is recognized and accounted for in accordance with GAAP. 
+• Management has performed a detailed review of revenues resulting from contracts as of March 31, 2014 and recorded
+the necessary adjustments. 
+(d) Changes in internal control. Except as discussed above, there was no change in our internal control over financial reporting that
+occurred during
+the fourth quarter of Fiscal 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. 
+Inherent Limitations on Internal Control 
+A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives
+of the control system are met. Further, the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can
+provide absolute assurance that all control issues and instances of management override or improper acts, if any, have been detected. These inherent limitations include the realities that judgments in
+decision making can be faulty, and that breakdowns can occur because of simple errors. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more
+people, or by management override of the control. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and there can be no
+assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to
+management override, error or improper acts may occur and not be detected. Any resulting misstatement or loss may have an adverse and material effect on our business, financial condition and results
+of operations. 
+Management's Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control
+system was designed to provide reasonable assurance to 
+38 
+Table of Contents 
+management
+and our Board of Directors regarding the effectiveness of our internal control processes over the preparation and fair presentation of published financial statements. 
+We
+have assessed the effectiveness of our internal controls over financial reporting as of March 31, 2014. In making this assessment, we used the criteria set forth by the
+Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework (2006) . Based on our assessment,
+we believe that, as of March 31, 2014, our internal control over financial reporting was not effective due to a material weakness related to our controls over the accounting for consulting
+services revenues. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a
+material misstatement of the Company's annual or interim financial statements will not be prevented or detected on a timely basis. 
+This
+annual report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Such a report is not
+required pursuant to the rules of the SEC applicable to smaller reporting companies. 
+ITEM 9B. OTHER INFORMATION 
+Effective February 21, 2014, we entered into a First Amendment to Lease (the "Amendment") with RREF II Freeway
+Acquisitions, LLC ("Landlord"). The Amendment modifies the Office Lease dated May 24, 2007 ("Lease") between us and Landlord's predecessor-in-interest, Crown Carnegie
+Associates, LLC, pursuant to which we lease our headquarters in Santa Ana, California. The Amendment reduces the size of the leased premises to approximately 41,000 rentable square feet and
+amends the term of the Lease to 96 months, beginning April 1, 2014. The monthly lease rate will be approximately $76,000 during the first year of the term and increase each year
+thereafter, up to a maximum of approximately $90,000 during the last year of the term. In addition, the Amendment provides for a second option to extend the term of the Lease by five years, for a
+total of two consecutive five year extension options under the Lease, as well as approximately $328,000 in incentives in the form of tenant improvement allowances. 
+39 
+Table of Contents 
+PART III 
+ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+Directors and Executive Officers 
+The table and narrative below set forth certain information, as of August 15, 2014, regarding our directors and executive
+officers. We believe our directors have the following other key attributes that are important to an effective board of directors: integrity and demonstrated high ethical standards; sound judgment;
+analytical skills; the ability to engage management and each other in a constructive and collaborative fashion; diversity of experience and thought; and the commitment to devote significant time and
+energy to service on our Board of Directors and its committees. 
+Name
+Age 
+Current Position(s) with Iteris 
+Richard Char(3) 
+55 
+Director 
+Kevin C. Daly, Ph.D.(2)(3) 
+70 
+Director 
+Gregory A. Miner(1) 
+59 
+Chairman of the Board 
+Abbas Mohaddes 
+57 
+Chief Executive Officer, President and Director 
+Gerard M. Mooney 
+60 
+Director 
+Thomas L. Thomas(1)(2)(3) 
+65 
+Director 
+Mikel H. Williams(1)(2) 
+57 
+Director 
+Todd Kreter 
+54 
+Senior Vice President and General Manager of Roadway Sensors 
+Thomas N. Blair 
+50 
+Senior Vice President, iPerform 
+Craig Christensen 
+36 
+Chief Financial Officer (Interim), Vice President and Controller 
+(1) Member
+of the Audit Committee
+(2) Member
+of the Compensation Committee
+(3) Member
+of the Nominating and Corporate Governance Committee 
+Richard Char has served as Senior Vice President of Business Development at VeriFone Holdings, Inc., global provider of technology
+for electronic payment transactions and value-added services at the point-of-sale, since July 2014. From August 2011 to April 2014, Mr. Char was Managing Director and Global Head of Digital
+Networks and Retail Solutions with Citi Enterprise Payments. Prior to joining Citi, Mr. Char was the Senior Managing Director at Regent Pacific Management Corporation, a turnaround,
+restructuring, and performance improvement firm, from September 2010 to August 2011. From October 2008 to March 2010, Mr. Char served as CEO of Incentium, LLC (formerly,
+VIPGift LLC), a provider of corporate and consumer loyalty and incentive programs. Incentium filed for bankruptcy protection in February 2011. From June 2006 to July 2008, Mr. Char was
+the Senior Vice President of Corporate Development and General Counsel of Blackhawk Network, Inc., then an affiliate of Safeway which markets pre-paid gift cards through leading
+U.S. retailers. Mr. Char's prior business experience includes serving as the President and Chief Executive Officer of IC Media, a developer of CMOS digital image sensors, as the Managing
+Director with the Technology Group of Credit Suisse First Boston, as Co-Head of Technology Investment Banking at Cowen & Company, and as a partner in the law firm of Wilson Sonsini
+Goodrich & Rosati. Mr. Char also served on the board of directors of Netlist, Inc. from January 2010 until December 2012. He received his A.B. degree from Harvard College and his
+J.D. degree from Stanford Law School. Mr. Char has served as a director since October 2005 and brings to the Board of Directors executive leadership experience, as well as significant corporate
+finance, legal and corporate development experience and financial acumen through his many years of work as a lawyer and in corporate finance. 
+Kevin C. Daly, Ph.D. has served as the CEO of Maxxess Systems, Inc., a provider of electronic security systems, since November
+2005. Between August 2007 and August 2009, Dr. Daly also served as 
+40 
+Table of Contents 
+CEO
+of iStor Networks, Inc., a manufacturer of IP SAN storage systems. Prior to that, he served as the CEO of several technology companies, including Avamar Technologies, Inc. and ATL
+Products, Inc. Dr. Daly served on the board of directors of sTec, Inc., a provider of solid state disk systems, from May 2010 until the acquisition of the company in September
+2013 by Western Digital Corporation. Dr. Daly received a B.S. degree in electrical engineering from the University of Notre Dame and M.S., M.A. and Ph.D degrees in engineering from
+Princeton University. He has served as a director of Iteris since 1993. Having served as the CEO of several technology companies and as a director of both private and public companies, Dr. Daly
+offers to the Board a wealth of management and leadership experience as well as an understanding of issues faced by such companies. 
+Gregory A. Miner has served as a Managing Partner of Merchant Capital Source, LLC, a company that provides working capital
+financing solutions to merchants, since 2004. Prior to that, Mr. Miner served in a number of management positions with us and our subsidiaries, most recently as our Chief Executive Officer.
+Mr. Miner is a Certified Public Accountant and his business experience includes work at Deloitte Haskins and Sells (now known as Deloitte LLP). Mr. Miner has served as a director
+since 1998 and as our Chairman of the Board of Directors since 2004. Through his service in a variety of executive positions with us and our subsidiaries, Mr. Miner has a deep and broad
+understanding of our business as well as the leadership skills and the operational understanding to provide sound guidance in continuing to grow our business. 
+Abbas Mohaddes has served as our Chief Executive Officer and President since March 2007 and as a director since September 2005. Prior to
+his promotion in March 2007, Mr. Mohaddes served as our Executive Vice President from October 2004. He also served in a number of executive positions with our former Iteris, Inc.
+subsidiary ("Iteris Subsidiary"), through which the majority of our current operations were conducted until we merged that subsidiary into us in October 2004. Mr. Mohaddes was also the
+President and Chief Executive Officer of Meyer, Mohaddes Associates, Inc. ("MMA"), an ITS and transportation firm that he co-founded, which was acquired by the Iteris Subsidiary in 1998.
+Mr. Mohaddes is an International Road Federation board member, a founding member and the past chairman of the board of Intelligent Transportation Society of America, a member of Transportation
+Research Board Executive Committee, Institute of Transportation Engineers, Forum for Corporate Directors, and UCI Chief Executive Roundtable. Mr. Mohaddes provides extensive technology,
+industry and management experience to the Board, as well as a substantial understanding of the Company and its operations resulting from his service as an officer of our Iteris Subsidiary and as the
+founder of MMA. 
+Gerard M. Mooney retired from International Business Machines Corporation ("IBM") in March 2014, after serving in a number of senior
+positions since 2000. Most recently, he served as the Vice President Strategy for IBM's Public Sector from February 2012 until his retirement, as the General Manager, Global Smarter Cities for IBM
+from November 2011 to February 2012, and as the General Manager, Global Government and Education for IBM from April 2008 to November 2011. Before joining IBM, Mr. Mooney held various management
+positions at Hewlett-Packard Company for six years. Mr. Mooney
+has extensive operational and financial experience across a broad range of technology-based companies, from start-ups to large public companies. He is actively involved in the intelligent
+transportation market and serves as a member of the board of directors of the Intelligent Transportation Society of America. He also has considerable experience with the major customers in the
+professional transportation market. He received a B.A. degree from Mount Saint Mary's College, an M.S. degree in Accounting from Georgetown University and an M.B.A. from Yale University.
+Mr. Mooney has served as a director of Iteris since September 2013 and brings to the Board of Directors extensive experience in setting and implementing strategy for both large and small
+technology organizations, deep category knowledge of the intelligent transportation market, and familiarity with many key customers for intelligent transportation solutions. 
+41 
+Table of Contents 
+Thomas L. Thomas has served as the Executive Chairman of International Decision Systems, a provider of software and solutions for the
+equipment finance market, since September of 2009. He also owns a management consulting business, T2 Partners. From 2004 until his retirement in July 2008, Mr. Thomas was as the President and
+Chief Operating Officer of Global Exchange Services, a provider of business-to-business EDI and supply chain management solutions. Prior to that, Mr. Thomas served as the President and CEO at
+several technology companies, including HAHT Commerce, Ajuba Solutions, and Vantive Corporation, and served in various senior and executive positions at 3Com Corporation, Dell Computer Corporation,
+Kraft General Foods and Sara Lee Corporation. Mr. Thomas also served on the board of directors of infoGroup, Inc. from January 2009 to July 2010. Mr. Thomas has served as a
+director of Iteris since 1999 and offers to the Board of Directors valuable business, leadership and strategic insights obtained through his service in a variety of industries, including a number of
+technology companies, and his experience in working with companies through several stages of their development. 
+Mikel H. Williams has served since May 2013 as the Chief Executive Officer and a director of JPS Industries, Inc., a manufacturer
+of sheet and mechanically formed glass and aramid substrate materials for the electronics, aerospace ballistics and general industrial applications. Prior to that, Mr. Williams was the
+President, Chief Executive Officer and a director of DDi Corp., a leading provider of time-critical, technologically advanced electronics manufacturing services, from November 2005 to May 2012 and a
+Senior Vice President and Chief Financial Officer of DDi from November 2004 to October 2005. Mr. Williams has also served in various management positions with several technology related
+companies. DDi was acquired by Viasystems Group, Inc. in May 2012. Mr. Williams began his career as a certified public accountant in the State of Maryland, working as an auditor for
+Price Waterhouse. Mr. Williams also serves on the boards of directors of USEC Inc. and Lightbridge Communications Corporation and served on the board of directors of Tellabs, Inc.
+until it was sold in December 2012. Mr. Williams was added to USEC's board of directors in October 2013 on the recommendation of certain holders of USEC's convertible senior notes as USEC was
+considering a bankruptcy restructuring, which is currently in process. Mr. Williams has served as a director of Iteris since April 2011 and provides the Board of Directors with operational and
+public company experience and valuable strategic insights through his many years of leadership positions in technology-related companies with international operations, as well as valuable knowledge
+and insights in finance and financial reporting matters. 
+Todd Kreter has served as Senior Vice President and General Manager of Roadway Sensors since May 2014. Mr. Kreter served as our
+Senior Vice President, Sensors Development and Operations, of the Company from May 2009 to May 2014 and as Vice President of Engineering from November 2007 to May 2009. Prior to joining us,
+Mr. Kreter served in a number of executive positions at Quantum Corporation, most recently as the VP Global Services from 2004 to January 2007, where he managed the company's worldwide customer
+service organization. Mr. Kreter holds an executive M.B.A. from Stanford/AEA and a B.S. degree in mechanical engineering from California State University, Fullerton. 
+Thomas N. Blair has served as Senior Vice President, iPerform, of the Company since July 2012. Prior to that, Mr. Blair served as
+general manager for Trimble Navigation Limited, a provider of integrated positioning, wireless, and software technology solutions, from 2007 to August 2011, and as vice president for new business
+development at @Road, Inc., a leading provider of mobile resource management solutions, from 2006 to 2007. He also worked as director of business and corporate development at iAnywhere
+Solutions, a Sybase company, from 2003 to 2006. Mr. Blair holds a B.S. degree in Management Information Systems from DeVry Institute of Technology and an M.S. degree in Computer
+Science from Rochester Institute of Technology. 
+Craig Christensen has served as our Chief Financial Officer (Interim) since July 2014, as Vice President since April 2014 and as
+Controller since April 2012. Prior to joining the Company, Mr. Christensen served as the Corporate Controller and Director of Finance and Accounting at 
+42 
+Table of Contents 
+SM&A,
+a provider of competition and program management services, from 2007 until April 2012. Prior to joining SM&A, Mr. Christensen served as a Manager in the Assurance Advisory &
+Business Services practice at Ernst & Young LLP. Mr. Christensen is a Certified Public Accountant in the State of California and holds a Bachelor of Arts degree in Business
+Economics with an emphasis in Accounting from the University of California, Santa Barbara. 
+Family Relationships 
+There are no family relationships among any of our directors or executive officers. 
+Code of Ethics and Business Conduct 
+Our Board of Directors has adopted a Code of Ethics and Business Conduct ("Code of Ethics") which applies to all directors, officers
+(including our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions) and employees. The full text of our Code
+of Ethics is available on the Investor Relations section of our website at www.iteris.com. We intend to disclose future amendments to certain provisions of the Code of Ethics, and any waivers of
+provisions of the Code of Ethics required to be disclosed under the rules of the SEC, at the same location on our website. 
+Audit Committee 
+We currently have several standing committees of the Board, including the Audit Committee, the Compensation Committee, and the
+Nominating and Corporate Governance Committee. The current members of our Audit Committee are Messrs. Miner, Thomas and Williams. The Board has determined that each member of the Audit
+Committee is "independent" under the listing standards of NYSE MKT and the SEC rules regarding audit committee memberships. The Board has identified Mr. Williams as the member of the Audit
+Committee who qualifies as an "audit committee financial expert" under applicable SEC rules and regulations governing the composition of the Audit Committee. 
+Changes in Nominating Procedures 
+There have been no material changes to the procedures by which security holders may recommend nominees to our Board that were
+implemented since we last disclosed such procedures. 
+Section 16(a) Beneficial Ownership Reporting Compliance 
+Under the federal securities laws, our directors and officers and any persons holding more than 10% of our common stock are required to
+report their ownership of our common stock and any changes in that ownership to the SEC. Specific due dates for these reports have
+been established, and we are required to report any failure to file by such dates. Based solely on our review of copies of the reports on Forms 3, 4 and 5 received by us during or with respect
+to the fiscal year ended March 31, 2014 and written representations received from the reporting persons that no other reports were required, we believe that all directors, executive officers
+and persons who own more than 10% of our common stock have complied with the reporting requirements of Section 16(a) and have filed all reports required by such section. 
+ITEM 11. EXECUTIVE COMPENSATION 
+Summary Compensation Table 
+The following table shows information regarding the compensation earned during the fiscal years ended March 31, 2013 and 2014 by
+(i) our Chief Executive Officer and (ii) our two most highly compensated executive officers (other than our Chief Executive Officer) who were serving as executive 
+43 
+Table of Contents 
+officers
+as of March 31, 2014. The officers listed below are collectively referred to as the "named executive officers" or "NEOs" in this report. 
+Name and Principal Position
+Fiscal 
+Year 
+Salary 
+Stock 
+Awards(1) 
+Option 
+Awards(2) 
+Non-Equity 
+Incentive Plan 
+Compensation(3) 
+All Other 
+Compensation(4) 
+Total 
+Abbas Mohaddes 
+2014 
+$ 
+376,910 
+— 
+$ 
+96,800 
+$ 
+51,316 
+$ 
+13,650 
+$ 
+538,676 
+Chief Executive Officer 
+2013 
+380,016 
+— 
+— 
+39,039 
+13,581 
+432,636 
+Todd Kreter 
+2014 
+213,013 
+— 
+38,720 
+38,372 
+6,771 
+296,876 
+Senior Vice President 
+2013 
+215,266 
+— 
+— 
+20,871 
+7,608 
+243,745 
+Thomas N. Blair 
+2014 
+230,006 
+— 
+32,848 
+6,569 
+269,423 
+Senior Vice President 
+2013 
+160,894 
+(5) 
+75,000 
+79,100 
+50,000 
+1,858 
+366,852 
+(1) The
+dollar amounts shown represent the grant date fair value of restricted stock units ("RSUs") granted during the applicable fiscal year calculated in
+accordance with the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") Topic 718, based on the closing sales price of the underlying shares of our common
+stock on the respective grant dates and without any adjustment for estimated forfeitures. Each RSU represents the right to receive one share of our common stock. The RSU awards vest in equal annual
+installments over four years, with the first installment vesting approximately one year after the grant date. Vested shares are issued as soon as practicable after the applicable vesting date.
+(2) The
+dollar amounts shown represent the grant date fair value of stock options granted during the applicable fiscal year determined pursuant to the
+Black-Scholes-Merton option pricing formula, in accordance with FASB ASC Topic 718. For a discussion of valuation assumptions used in the calculations, see Note 11 of Notes to Consolidated
+Financial Statements, included in Part IV, Item 15 of this report. See also our discussion of stock-based compensation under "Management's Discussion and Analysis of Financial Condition
+and Results of Operations—Critical Accounting Policies and Estimates". The options have an exercise price equal to the closing sales price of our common stock as of the grant date, vest in
+equal annual installments over four years, and are not exercisable until vested.
+(3) The
+amounts shown in this column constitute the cash bonuses paid to each named executive officer based on the attainment of certain pre-established
+criteria. These awards are discussed in further detail under "Plan-Based Bonuses" below.
+(4) Represents
+401(k) plan employer contributions and automobile allowances paid by us.
+(5) Mr. Blair
+was hired on July 10, 2012 at an annual salary of $230,000. The Fiscal 2013 salary represents the amount earned by Mr. Blair
+from his hire date to the end of Fiscal 2013. 
+Plan-Based Bonuses 
+For Fiscal 2014, the potential compensation for Messrs. Mohaddes, Kreter and Blair included an annual cash bonus based upon
+criteria established by the Compensation Committee at the beginning of the fiscal year. The bonuses were entirely based on our corporate and business unit performance and achievements. For
+Mr. Mohaddes, 70% of his potential bonus was based on the total revenue and operating income achieved by the Company for the year, 10% of his potential bonus was based on revenue achieved by
+the iPerform segment, and 20% of his potential bonus was
+based on achieving certain milestones with respect to the iPerform segment. For Mr. Kreter, 50% of his potential bonus was based on the total revenue and operating income achieved by the
+Company, 40% of his potential bonus was based on revenue and operating income achieved by the Roadway Sensors segment, and 10% of his potential bonus was based on revenue achieved by the iPerform
+segment. For Mr. Blair, 40% of his potential bonus was based on the total revenue and operating income achieved by the Company, 30% of his potential bonus was based on revenue and operating
+income achieved by the iPerform segment, and 30% of his potential bonus was based on achieving certain milestones with respect to the iPerform segment. 
+44 
+Table of Contents 
+The milestones to be achieved by Messrs. Mohaddes and Blair with respect to the iPerform segment for bonus purposes were (i) achieving development
+milestones according to the approved Fiscal 2014 plan, which generally consisted of research and development, business development and marketing goals, and (ii) adding $10 million of
+backlog during Fiscal 2014, with no bonuses payable with respect to such milestone at or below $8.5 million of backlog. 
+The
+corporate and business unit performance targets for the annual cash bonuses for Messrs. Mohaddes, Kreter and Blair for Fiscal 2014 were as follows: 
+Performance Component(1)
+No Bonuses 
+At or Below 
+Target 
+Maximum 
+(in thousands) 
+Corporate Revenue 
+$ 
+61,285 
+$ 
+72,100 
+$ 
+79,310 
+Corporate Operating Income 
+2,120 
+2,650 
+2,915 
+Roadway Sensors Revenue 
+28,980 
+32,200 
+33,810 
+Roadway Sensors Operating Income 
+3,680 
+4,600 
+5,290 
+iPerform Revenue 
+7,560 
+8,400 
+9,240 
+iPerform Operating Loss 
+(2,040 
+) 
+(2,550 
+) 
+(2,933 
+) 
+(1) The
+corporate revenue and operating income goals and the iPerform revenue goal were applicable to each NEO, the Roadway Sensors revenue and operating income
+goals were applicable to Mr. Kreter, and the iPerform Operating Income goal was applicable to Mr. Blair. 
+The
+potential bonuses at target for Fiscal 2014 were as follows: Mr. Mohaddes—$175,000; Mr. Kreter—$115,000; and
+Mr. Blair—$115,000. If our performance for Fiscal 2014 exceeded the revenue and operating income targets set for bonus purposes, the executives could have earned an additional bonus
+of up to 50% of the target bonus award that was not based upon achieving milestones. The full 50% additional bonus would have been earned by the NEOs if the Company had achieved the revenue and
+operating income goals set forth under the "Maximum" column above. If the Company had achieved revenue and operating income which were less than the goals set forth under the "Maximum" column but more
+than the amounts set forth under the "Target" column, the additional bonus payable would have been proportional, or based on the level of the Maximum goal achieved when measured from the Target
+amount. For example, if the performance had exceeded the Target goal by 25% of the difference between the Maximum and Target amounts, then 25% of the 50% additional bonus relating to such performance
+goal would have been payable. 
+In
+Fiscal 2014, our actual revenue and operating results for the Company and for the relevant business units were as follows: Corporate Revenue—$68.2 million;
+Corporate Operating Income—$2.0 million; Roadway Sensors Revenue—$31.8 million; Roadway Sensors Operating Income—$3.7 million; iPerform
+Revenue—$5.9 million; and iPerform Operating Loss—$(2.5) million. As a percentage of the targets set for bonus purposes, the results were as follows: Corporate
+Revenue—94.6%; Corporate Operating Income—76.4%; Roadway Sensors Revenue—98.7%; Roadway Sensors Operating Income—79.4%; iPerform
+Revenue—70.7%; and iPerform Operating Income—103.3%. For bonus purposes, segment operating income results include certain corporate allocations. Accordingly, based upon the
+above described criteria, bonuses in the following amounts were approved for Fiscal 2014: Mr. Mohaddes—$51,316; Mr. Kreter—$38,372; and
+Mr. Blair—$32,848. 
+45 
+Table of Contents 
+Outstanding Equity Awards at Fiscal Year-End 
+The following table sets forth the outstanding equity awards held by each named executive officer as of March 31, 2014. 
+Option Awards 
+Stock Awards 
+Name
+Number of 
+Securities 
+Underlying 
+Unexercised 
+Options 
+(#) 
+Exercisable 
+Number of 
+Securities 
+Underlying 
+Unexercised 
+Options (#) 
+Unexercisable 
+Option 
+Exercise 
+Price ($) 
+Option 
+Grant 
+Date(1) 
+Option 
+Expiration 
+Date 
+Number of 
+Shares or 
+Units of 
+Stock 
+That Have 
+Not 
+Vested(2) 
+Market Value 
+of Shares or 
+Units of 
+Stock That 
+Have Not 
+Vested(3) 
+Abbas Mohaddes 
+30,000 
+— 
+$ 
+2.21 
+06/15/06 
+06/14/16 
+12,500 
+(4) 
+$ 
+24,750 
+Chief Executive Officer 
+100,000 
+— 
+2.55 
+03/14/07 
+03/13/17 
+200,000 
+— 
+2.34 
+10/02/07 
+10/01/17 
+100,000 
+— 
+1.41 
+05/27/09 
+05/26/19 
+37,500 
+37,500 
+1.10 
+08/10/11 
+08/09/21 
+— 
+100,000 
+1.81 
+07/29/13 
+07/28/23 
+Todd Kreter 
+25,000 
+— 
+2.46 
+02/21/08 
+02/20/18 
+6,250 
+(4) 
+12,375 
+Senior Vice President 
+25,000 
+— 
+1.41 
+05/27/09 
+05/26/19 
+10,000 
+(5) 
+19,800 
+15,000 
+15,000 
+1.10 
+08/10/11 
+08/09/21 
+— 
+40,000 
+1.81 
+07/29/13 
+07/28/23 
+Thomas N. Blair 
+25,000 
+75,000 
+1.50 
+08/09/12 
+08/08/22 
+37,500 
+(6) 
+74,250 
+Senior Vice President 
+(1) Each
+option vests at the rate of 25% on each of the first four anniversaries of the grant date.
+(2) Indicates
+the number of shares of common stock subject to restricted stock unit ("RSU") awards. Each RSU represents the right to receive one share of our
+common stock.
+(3) The
+dollar amounts represent the market value of the shares subject to the RSUs, calculated by multiplying the closing sales price of our common stock on
+the last business day of Fiscal 2014 by the applicable number of shares.
+(4) The
+original RSU award was granted on August 12, 2010 and vests in equal annual installments over four years. The first installment vested on
+August 10, 2011. The shares indicated represent the remaining unvested amount.
+(5) The
+original RSU award was granted on August 10, 2011 and vests in equal annual installments over four years. The first installment vested on
+August 10, 2012. The shares indicated represent the remaining unvested amount.
+(6) The
+original RSU award was granted on August 9, 2012 and vests in equal annual installments over four years. The first installment vested on
+August 9, 2013. The shares indicated represent the remaining unvested amount. 
+Employment Contracts; Termination of Employment and Change of Control Arrangements 
+We do not currently have any employment contracts in effect with any of our named executive officers other than the agreements
+described below. We provide incentives such as salary, benefits and option grants to attract and retain executive officers and other key associates. The plan administrators of the 1997 Stock Incentive
+Plan and the 2007 Omnibus Incentive Plan have the authority to provide for the accelerated vesting of outstanding options held by an individual in connection with the termination of such individual's
+employment following an acquisition in which these options are 
+46 
+Table of Contents 
+assumed
+or the repurchase rights with respect to the unvested shares are assigned or upon certain changes in control of the Company. Other than such accelerated vesting and the agreements described
+above, there is no agreement or policy which would entitle any executive officer to severance payments or any other compensation as a result of such officer's termination. 
+Agreement with Abbas Mohaddes 
+On July 29, 2013, we entered into an Employment Agreement (the "Employment Agreement") with Abbas Mohaddes, our Chief Executive
+Officer. The Employment Agreement has an initial term of three years and thereafter renews automatically for successive one year periods until ten years after the effective date (such initial term
+together with any renewal periods, the "Employment Period"), unless either party provides written notice of nonrenewal at least 30 days prior to the end of the initial term or any renewal
+period. Under the terms of the Employment Agreement, Mr. Mohaddes is entitled to an initial base salary of $380,000 per year, which may be
+increased from time to time at the sole discretion of the Compensation Committee of our Board of Directors. In the event that he is terminated without Cause (as defined in the Employment Agreement)
+during the Employment Period, Mr. Mohaddes is entitled to (i) salary continuation for 12 months following termination (or a lump sum payment equal to his base salary in the event
+the termination without Cause occurs within 12 months after a Change in Control (as defined in the Employment Agreement)), (ii) a lump sum payment equal to 50% of his average annual
+target bonus for the two years immediately preceding the year of termination, payable no later than 30 days following termination, and (iii) reimbursement for the cost to continue health
+benefit coverage under the Consolidated Omnibus Budget Reconciliation Act (COBRA) for a period of up to one year following termination. If his employment is terminated as a result of death or
+disability, then Mr. Mohaddes (or his estate) will be entitled to, in the case of death, a lump sum payment equal to 50% of his then effective base salary and, in the case of disability, salary
+continuation of up to 90 days until he is eligible for short-term disability payments. In the event that he resigns for Good Reason (as defined in the Employment Agreement) after a Change in
+Control, in lieu of any other benefits under the Employment Agreement, Mr. Mohaddes will be entitled to (I) a lump sum payment equal to one year's base salary plus an amount equal to 50%
+of his average annual target bonus for the two years immediately preceding the year of termination, payable no later than 30 days following termination, and (II) reimbursement for the
+cost to continue health benefit coverage under COBRA for a period of up to one year following termination. 
+Director Compensation 
+Directors who are not employees of Iteris or any of its subsidiaries receive an annual retainer of $28,000 per year, paid quarterly,
+with the Chairman of the Board receiving an additional $10,000 per year. No additional amounts are paid for attending meetings. In addition, each non-employee director who serves on a Board committee
+receives the following annual amounts, paid quarterly: Audit Committee—$2,500 ($5,000 for the Chair); Compensation Committee—$1,500 ($3,000 for the Chair); Nominating and
+Governance Committee—$1,000 ($2,000 for the Chair); ad hoc committees—$500 ($1,000 for the Chair). All directors are reimbursed for their out-of-pocket expenses incurred in
+attending meetings of our Board of Directors and its committees. 
+Non-employee
+directors are also eligible to receive periodic option grants pursuant to the Directors' Automatic Option Grant Program under our 2007 Omnibus Incentive Plan. Under that
+plan, each non-employee director receives an option to purchase 20,000 shares of common stock upon his initial appointment to the Board of Directors and an additional option to purchase 10,000 shares
+of common stock on the date of each annual meeting provided he has served on the Board for at least six months as of such annual meeting. Each such option is immediately exercisable for any or all of
+the option shares, but the shares acquired are subject to repurchase by the Company at the exercise price paid per share if the optionee ceases service with the Company prior to vesting in those
+shares. Each 
+47 
+Table of Contents 
+option
+vests in full upon the optionee's completion of one year of service measured from the grant date. However, the vesting of each such option will accelerate in full upon certain changes in
+control of the Company or upon the optionee's death or disability while a director. Each option granted to non-employee directors under the Directors' Automatic Option Grant Program will have an
+exercise price equal to the fair market value of the common stock on the grant date and a maximum term of ten years, subject to earlier termination following the optionee's cessation of service as a
+Board member. Following the optionee's cessation of Board service for any reason, each option will remain exercisable for a 12-month period and may be exercised during that time for any or all shares
+in which the optionee is vested at the time of such cessation of service as a director. 
+The
+following table sets forth a summary of the compensation earned in Fiscal 2014 by each person who served as a director during such year, who is not a named executive officer. 
+Name
+Fees Earned or 
+Paid in Cash 
+($)(1) 
+Option 
+Awards 
+($)(2) 
+Total ($) 
+Richard Char 
+$ 
+29,000 
+$ 
+9,382 
+$ 
+38,382 
+Kevin C. Daly, Ph.D. 
+33,500 
+9,382 
+42,882 
+Gregory A. Miner 
+41,500 
+9,382 
+50,882 
+Gerard M. Mooney 
+14,000 
+18,763 
+32,763 
+Thomas L. Thomas 
+33,000 
+9,382 
+42,382 
+Mikel H. Williams 
+34,500 
+9,382 
+43,882 
+(1) Represents
+amounts earned by the directors based on the compensation arrangement described above.
+(2) The
+dollar amounts shown represent the grant date fair value of stock options granted in Fiscal 2014 determined pursuant to the Black-Scholes-Merton option
+pricing formula, in accordance with FASB ASC Topic 718. For a discussion of valuation assumptions used in the calculations, see Note 11 of Notes to Consolidated Financial Statements, included
+in Part IV, Item 15 of this report. See also our discussion of stock-based compensation under "Management's Discussion and Analysis of Financial Condition and Results of
+Operations—Critical Accounting Policies and Estimates". At the end of Fiscal 2014, the non-employee directors held options for the following number of shares of common stock: Richard
+Char—75,000; Kevin C. Daly, Ph.D.—65,000; Gregory A. Miner—60,000; Gerard M. Mooney—20,000; Thomas L. Thomas—65,000; and Mikel H.
+Williams—40,000. 
+Indemnification of Directors and Officers 
+Under Section 145 of the Delaware General Corporation Law, we can indemnify our directors and officers against liabilities they
+may incur in such capacities, including liabilities under the Securities Act of 1933, as amended. Our certificate of incorporation and bylaws provide that we will indemnify our directors and officers
+to the fullest extent permitted by law, and our bylaws require us to advance litigation expenses upon receipt of an undertaking by the director or officer to repay such advances if it is ultimately
+determined that the director or officer is not entitled to indemnification. The bylaws further provide that rights conferred under such bylaws do not exclude any other right such persons may have or
+acquire under any bylaw, agreement, vote of stockholders or disinterested directors or otherwise. 
+Our
+certificate of incorporation provides that, pursuant to Delaware law, our directors shall not be liable for monetary damages for breach of the directors' fiduciary duty of care to us
+and our stockholders. This provision in the certificate of incorporation does not eliminate the duty of care, and 
+48 
+Table of Contents 
+in
+appropriate circumstances equitable remedies such as injunctive or other forms of non-monetary relief will remain available under Delaware law. In addition, each director will continue to be
+subject to liability for breach of the director's duty of loyalty to us or our stockholders, for acts or omissions not in good faith or involving intentional misconduct or knowing violations of law,
+for actions leading to improper personal benefit to the director, and for payment of dividends or approval of stock repurchases or redemptions that are unlawful under Delaware law. The provision also
+does not affect a director's responsibilities under any other law, such as the federal securities laws or state or federal environmental laws. 
+We
+have entered into agreements to indemnify certain of our directors and officers in addition to the indemnification provided for in the certificate of incorporation and bylaws. These
+agreements, among other things, indemnify such directors and officers for certain expenses (including attorneys' fees), judgments, fines and settlement amounts incurred by such person in any action or
+proceeding, including any action by or in the right of the Company, on account of services as a director or officer of Iteris, or as a director or officer of any other company or enterprise to which
+the person provides services at our request. 
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+Common Stock Ownership of Certain Beneficial Owners and Management 
+The following table sets forth, as of August 15, 2014, the number and percentage ownership of our common stock by (i) all
+persons known to us to beneficially own more than 5% of the outstanding common stock, (ii) each of the named executive officers in the Summary Compensation Table which appears elsewhere herein,
+(iii) each of our directors, and (iv) all of our executive officers and directors as a group. To our knowledge, except as otherwise indicated, each of the persons named in this table has
+sole voting and investment power with respect to the common stock shown as beneficially owned, subject to community property and similar laws, where applicable. 
+Common Stock 
+Name and Address of Beneficial Owner(1)
+Amount and 
+Nature of 
+Beneficial 
+Ownership(2) 
+Percent of 
+Class(2) 
+Lloyd I. Miller, III(3) 
+5,367,630 
+16.5 
+% 
+Thomson Horstmann & Bryant, Inc.(4) 
+2,070,852 
+6.4 
+Abbas Mohaddes(5) 
+1,398,691 
+4.2 
+Todd Kreter(6) 
+111,060 
+* 
+Thomas N. Blair(7) 
+66,401 
+* 
+Richard Char(8) 
+84,000 
+* 
+Kevin C. Daly, Ph.D(9) 
+420,132 
+1.3 
+Gregory A. Miner(10) 
+687,485 
+2.1 
+Gerard M. Mooney(11) 
+20,000 
+* 
+Thomas L. Thomas(12) 
+104,000 
+* 
+Mikel H. Williams(13) 
+50,000 
+* 
+All executive officers and directors as a group (10 persons)(14) 
+2,963,019 
+8.8 
+% 
+* Less
+than 1%.
+(1) The
+address of each of the directors and officers is 1700 Carnegie Avenue, Suite 100, Santa Ana, CA 92705. 
+49 
+Table of Contents 
+(2) Based
+on 32,608,874 shares of common stock outstanding as of August 15, 2014. Shares of common stock subject to options which are exercisable within
+60 days of August 15, 2014 are deemed to be beneficially owned by the person holding such options or warrants for the purpose of computing the percentage of ownership of such person but
+are not treated as outstanding for the purpose of computing the percentage of any other person. Other than as described in the preceding sentence, shares issuable upon exercise of outstanding options
+and warrants are not deemed to be outstanding for purposes of this calculation. In addition to the shares held in the individual's name, the number of shares indicated also includes shares held for
+the benefit of the named person under our 401(k) and Stock Ownership Plan.
+(3) Pursuant
+to an amendment to a Schedule 13G filed on February 12, 2014 with the SEC, Mr. Miller reported that, as of December 31,
+2013, he had sole dispositive and voting power with respect to 5,231,993 shares as (i) the manager of a limited liability company that is the general partner of certain limited partnerships,
+(ii) the manager of a limited liability company that is the adviser to certain trusts, (iii) the manager of a limited liability company and (iv) an individual. As of such date,
+Mr. Miller also had shared dispositive and voting power with respect to 135,637 shares as (i) an advisor to the trustee of a certain trust and (ii) an authorized person with
+respect to a custody account. The address for Mr. Miller is 222 Lakeview Avenue, Suite 160-365, West Palm Beach, Florida 33401.
+(4) Pursuant
+to a Schedule 13G filed on February 6, 2014 with the SEC, Thomson Horstmann & Bryant, Inc. reported that it had sole
+dispositive power over 2,070,852 shares (and shared voting power over 968,391 shares). The address for Thomson Horstmann & Bryant, Inc. is 501 Merritt 7, Norwalk, CT 06851.
+(5) Includes
+(i) 492,500 shares issuable upon exercise of options that are currently exercisable or will become exercisable within 60 days after
+August 15, 2014 and (ii) 11,540 shares held by Mr. Mohaddes' IRA.
+(6) Includes
+82,500 shares issuable upon exercise of options that are currently exercisable or will become exercisable within 60 days after
+August 15, 2014.
+(7) Includes
+50,000 shares issuable upon exercise of options that are currently exercisable or will become exercisable within 60 days after
+August 15, 2014.
+(8) Includes
+(i) 75,000 shares issuable upon exercise of options that are currently exercisable or will become exercisable within 60 days after
+August 15, 2014 and (ii) 9,000 shares held by the Char-Yoshida Family Trust, of which Mr. Char is a co-trustee.
+(9) Includes
+(i) 100 shares held by Dr. Daly's spouse, (ii) 329,032 shares held by Dr. Daly's IRA, and (iii) 65,000 shares
+issuable upon exercise of options that are currently exercisable or will become exercisable within 60 days after August 15, 2014.
+(10) Includes
+(i) 183,334 shares held by Mr. Miner's IRA, (ii) 19,230 shares held by Mr. Miner's wife's IRA and (iii) 60,000
+shares issuable upon exercise of options that are currently exercisable or will become exercisable within 60 days after August 15, 2014.
+(11) Includes
+20,000 shares issuable upon exercise of options that are currently exercisable or will become exercisable within 60 days after
+August 15, 2014.
+(12) Includes
+65,000 shares issuable upon exercise of options that are currently exercisable or will become exercisable within 60 days after
+August 15, 2014.
+(13) Includes
+40,000 shares issuable upon exercise of options that are currently exercisable or will become exercisable within 60 days after
+August 15, 2014.
+(14) Includes
+963,750 shares issuable upon exercise of options that are currently exercisable or will become exercisable within 60 days after
+August 15, 2014. The number indicated includes shares held by Craig Christensen, who was appointed as our Chief Financial Officer (Interim) in July 2014. 
+50 
+Table of Contents 
+Equity Compensation Plans 
+The following table provides information as of March 31, 2014 with respect to shares of our common stock that may be issued
+under existing equity compensation plans. 
+Plan Category
+Number of Securities to 
+be Issued Upon Exercise 
+of Outstanding Options, 
+Warrants and Rights 
+Weighted Average 
+Exercise Price of 
+Outstanding Options, 
+Warrants and Rights 
+Number of Securities 
+Remaining Available For 
+Future Issuance under 
+Equity Compensation Plans 
+(excluding securities 
+reflected in first column) 
+Equity Compensation Plans Approved by Security Holders 
+1997 Stock Incentive Plan 
+262,000 
+$ 
+2.74 
+— 
+2007 Omnibus Incentive Plan 
+1,952,000 
+(1) 
+1.75 
+(2) 
+263,000 
+Equity Compensation Plans Not Approved by Security Holders 
+None 
+— 
+— 
+— 
+Total 
+2,214,000 
+(1) 
+$ 
+1.88 
+(2) 
+263,000 
+(1) Includes
+195,000 shares of our common stock subject to RSUs that entitle each holder to one share of common stock for each such unit that vests over the
+holder's period of continued service.
+(2) Calculated
+without taking into account the 195,000 shares of common stock subject to outstanding RSUs that become issuable as those units vest, without the
+payment of any additional consideration or exercise price. 
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+Certain Transactions 
+Since April 1, 2012, other than the agreements and transactions described in Part III, Item 11 and the
+transactions described below, there has not been, nor is there any proposed transaction, where we (or any of our subsidiaries) were or will be a party in which the amount involved exceeded or will
+exceed the lesser of $120,000 or the average of our total assets at year end for the last two fiscal years and in which any director, executive officer, holder of more than 5% of any class of our
+voting securities, or any member of the immediate family of any of the foregoing persons had or will have a direct or indirect material interest. 
+We
+previously subleased office space to Maxxess Systems, Inc. ("Maxxess"), one of our former subsidiaries that we sold in September 2003 and is currently owned by an investor
+group that includes
+Mr. Daly, a current director of Iteris and the Chief Executive Officer of Maxxess, and Joel Slutzky, a former director of Iteris. The sublease terminated in September 2007, at which time
+Maxxess owed us an aggregate of $274,000 related to this sublease and certain ancillary corporate services that we provided to Maxxess. In August 2009, Maxxess executed a promissory note payable to us
+for $274,000. The promissory note accrued interest at a rate of 6% per annum, compounded annually, with such interest to be paid annually on the first business day of each calendar year. Payments
+under the note may be made in bona fide services rendered by Maxxess to us to the extent such services and amounts are pre-approved in writing by us. All amounts outstanding under the note was to
+become due and payable on the earliest of (i) August 10, 2014, (ii) a change of control in Maxxess, or (iii) a financing by Maxxess resulting in gross proceeds of at least
+$10 million. 
+On
+July 23, 2013, the promissory note with Maxxess was amended and restated. The amended and restated note bears interest at a rate of 6% per annum, compounded annually, with
+accrued interest to 
+51 
+Table of Contents 
+be
+paid quarterly on the first business day of each calendar quarter. Payments under the amended and restated note may only be made in cash and all amounts outstanding will become due and payable on
+the earliest of (i) August 10, 2016, (ii) a change of control in Maxxess or (iii) a financing by Maxxess resulting in gross proceeds of at least $10 million. As of
+March 31, 2014 and as of August 15, 2014, approximately $259,000 of the original principal balance was outstanding and payable to us. During each of Fiscal 2013 and Fiscal 2014, interest
+payments totaling approximately $16,000 were made by Maxxess. We have previously fully reserved for amounts owed to us by Maxxess and all outstanding principal remains fully reserved. 
+Director Independence 
+The Board of Directors has determined that each of Messrs. Char, Daly, Miner, Mooney, Thomas and Williams satisfies the
+requirements for "independence" under the listing standards of NYSE MKT. 
+ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES 
+Principal Accountant Fees 
+The following table presents the aggregate fees billed by McGladrey LLP for the indicated services for the fiscal years ended
+March 31, 2013 and 2014: 
+Fiscal Year Ended 
+March 31, 
+2013 
+2014 
+Audit Fees 
+$ 
+275,000 
+$ 
+1,082,000 
+Audit-Related Fees 
+52,000 
+50,000 
+Tax Fees 
+105,000 
+27,000 
+All Other Fees 
+— 
+— 
+Total Fees 
+$ 
+432,000 
+$ 
+1,159,000 
+Audit Fees. Audit fees consist of fees for professional services rendered in connection with the audit of our annual
+consolidated financial
+statements and review of the consolidated financial statements included in our quarterly reports on Form 10-Q and other regulatory filings. Additionally, audit fees include professional
+services rendered in connection with the Company's annual statutory overhead rate audits. 
+Audit-Related Fees. Audit-related fees consist of fees for professional services that are reasonably related to the performance
+of the audit or
+review of our consolidated financial statements but are not reported under "Audit Fees." Such fees include, among other things, fees for registration statements, fees for internal control reviews and
+assistance with meeting the requirements of Section 404 of the Sarbanes-Oxley Act and certain consultations concerning financial accounting and reporting standards. 
+Tax Fees. Tax fees consist of fees billed to us by McGladrey LLP during the fiscal years ended March 31, 2013 and 2014
+for tax
+compliance services, which include the preparation of federal, state and international tax returns, and for tax consultations, including tax planning and federal, state and international tax advice. 
+All Other Fees. There were no other fees billed to us by McGladrey LLP during the fiscal years ended March 31, 2013
+and 2014. 
+Audit Committee Pre-Approval Policies and Procedures 
+All engagements for services by McGladrey LLP or other independent registered public accountants are subject to prior approval
+by the Audit Committee; however, de minimis non-audit services may instead be approved in accordance with applicable SEC rules. The prior
+approval of the Audit Committee was obtained for all services provided by McGladrey LLP for the fiscal year ended March 31, 2014. 
+52 
+Table of Contents 
+PART IV 
+ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES 
+(a) Documents
+filed as part of this report: 
+1. Financial Statements . The following financial statements of Iteris, Inc. are
+included in a
+separate section of this Annual Report on Form 10-K commencing on the pages referenced below: 
+Report of Independent Registered Public Accounting Firm 
+57 
+Consolidated Balance Sheets as of March 31, 2014 and 2013 
+58 
+Consolidated Statements of Operations for the fiscal years ended March 31, 2014, 2013 and 2012 
+59 
+Consolidated Statements of Stockholders' Equity for the fiscal years ended March 31, 2014, 2013 and 2012 
+60 
+Consolidated Statements of Cash Flows for the fiscal years ended March 31, 2014, 2013 and 2012 
+61 
+Notes to Consolidated Financial Statements 
+62 
+2. Exhibits . 
+The
+exhibits listed on the accompanying Exhibit Index immediately following the financial statements are filed as part of, or hereby incorporated by reference into, this report. 
+53 
+Table of Contents 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this
+report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+Dated: September 3, 2014 
+ITERIS, INC. 
+(Registrant) 
+By 
+/s/ ABBAS MOHADDES 
+Abbas Mohaddes 
+Chief Executive Officer 
+(Principal Executive Officer) 
+POWER OF ATTORNEY 
+We, the undersigned officers and directors of Iteris, Inc., do hereby constitute and appoint Craig. A Christensen and
+Abbas Mohaddes, and each of them, our true and lawful attorneys-in-fact and agents, each with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all
+capacities, to sign any and all amendments to this report, and to file the same, with exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission,
+granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite or necessary to be done in and about the premises,
+as fully to all intents and purposes as he might or could do in person, hereby, ratifying and confirming all that each of said attorneys-in-fact and agents, or his substitute or substitutes, may
+lawfully do or cause to be done by virtue hereof. 
+Pursuant
+to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the registrant in the capacities
+and on the dates indicated: 
+Signature
+Title
+Date
+/s/ ABBAS MOHADDES 
+Abbas Mohaddes 
+Director, President and Chief Executive Officer 
+(principal executive officer) 
+September 3, 2014 
+/s/ CRAIG A. CHRISTENSEN 
+Craig A. Christensen 
+Chief Financial Officer (Interim) (principal financial and accounting officer) 
+September 3, 2014 
+/s/ GREGORY A. MINER 
+Gregory A. Miner 
+Chairman of the Board 
+September 3, 2014 
+/s/ RICHARD CHAR 
+Richard Char 
+Director 
+September 3, 2014 
+54 
+Table of Contents 
+Signature
+Title
+Date
+/s/ KEVIN C. DALY 
+Kevin C. Daly, Ph.D. 
+Director 
+September 3, 2014 
+/s/ GERARD M. MOONEY 
+Gerard M. Mooney 
+Director 
+September 3, 2014 
+/s/ THOMAS L. THOMAS 
+Thomas L. Thomas 
+Director 
+September 3, 2014 
+/s/ MIKEL WILLIAMS 
+Mikel Williams 
+Director 
+September 3, 2014 
+55 
+Table of Contents 
+Iteris, Inc. 
+Index to Consolidated Financial Statements 
+Report of Independent Registered Public Accounting Firm 
+57 
+Consolidated Balance Sheets as of March 31, 2014 and 2013 
+58 
+Consolidated Statements of Operations for the fiscal years ended March 31, 2014, 2013 and
+2012 
+59 
+Consolidated Statements of Stockholders' Equity for the fiscal years ended March 31, 2014, 2013 and
+2012 
+60 
+Consolidated Statements of Cash Flows for the fiscal years ended March 31, 2014, 2013 and
+2012 
+61 
+Notes to Consolidated Financial Statements 
+62 
+56 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+To
+the Board of Directors and Stockholders 
+Iteris, Inc. 
+We
+have audited the accompanying consolidated balance sheets of Iteris, Inc. and subsidiaries as of March 31, 2014 and 2013, and the related consolidated statements of
+operations, stockholders' equity, and cash flows for each of the three years in the period ended March 31, 2014. These financial statements are the responsibility of the Company's management.
+Our responsibility is to express an opinion on these financial statements based on our audits. 
+We
+conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to
+obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal
+control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances,
+but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes
+examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well
+as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. 
+In
+our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Iteris, Inc. and subsidiaries as of
+March 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended March 31, 2014, in conformity with U.S. generally
+accepted accounting principles. 
+/s/
+McGladrey LLP 
+Irvine, California 
+September 3, 2014 
+57 
+Table of Contents 
+Iteris, Inc. 
+Consolidated Balance Sheets 
+(In thousands, except par value) 
+March 31, 
+2014 
+2013 
+Assets 
+Current assets: 
+Cash and cash equivalents 
+$ 
+20,414 
+$ 
+18,678 
+Trade accounts receivable, net of allowance for doubtful accounts of $532 and $322 at March 31, 2014 and March 31, 2013,
+respectively 
+12,349 
+10,946 
+Costs and estimated earnings in excess of billings on uncompleted contracts 
+5,813 
+6,346 
+Inventories 
+2,546 
+2,465 
+Deferred income taxes 
+1,429 
+2,363 
+Prepaid expenses and other current assets 
+1,275 
+1,311 
+Total current assets 
+43,826 
+42,109 
+Property and equipment, net 
+1,546 
+1,862 
+Deferred income taxes 
+6,112 
+5,888 
+Intangible assets, net 
+1,584 
+2,124 
+Goodwill 
+17,318 
+17,318 
+Other assets 
+221 
+210 
+Total assets 
+$ 
+70,607 
+$ 
+69,511 
+Liabilities and stockholders' equity 
+Current liabilities: 
+Trade accounts payable 
+$ 
+5,913 
+$ 
+5,411 
+Accrued payroll and related expenses 
+3,971 
+3,374 
+Accrued liabilities 
+1,643 
+1,979 
+Billings in excess of costs and estimated earnings on uncompleted contracts 
+1,391 
+1,958 
+Total current liabilities 
+12,918 
+12,722 
+Deferred rent 
+— 
+312 
+Unrecognized tax benefits 
+199 
+286 
+Other non-current liabilities 
+— 
+310 
+Total liabilities 
+13,117 
+13,630 
+Commitments and contingencies 
+Stockholders' equity: 
+Preferred stock, $1.00 par value: 
+Authorized shares—2,000 
+Issued and outstanding shares—none 
+— 
+— 
+Common stock, $0.10 par value: 
+Authorized shares—70,000 at March 31, 2014 and March 31, 2013 
+Issued and outstanding shares—32,788 at March 31, 2014 and 32,626 at March 31, 2013 
+3,280 
+3,264 
+Additional paid-in capital 
+135,986 
+135,802 
+Accumulated deficit 
+(81,776 
+) 
+(83,185 
+) 
+Total stockholders' equity 
+57,490 
+55,881 
+Total liabilities and stockholders' equity 
+$ 
+70,607 
+$ 
+69,511 
+See accompanying notes. 
+58 
+Table of Contents 
+Iteris, Inc. 
+Consolidated Statements of Operations 
+(In thousands, except per share amounts) 
+Year Ended March 31, 
+2014 
+2013 
+2012 
+Total revenues 
+$ 
+68,228 
+$ 
+61,685 
+$ 
+58,406 
+Cost of revenues 
+42,254 
+38,427 
+35,335 
+Gross profit 
+25,974 
+23,258 
+23,071 
+Operating expenses: 
+Selling, general and administrative 
+19,269 
+18,090 
+17,986 
+Research and development 
+4,029 
+3,071 
+3,183 
+Amortization of intangible assets 
+627 
+644 
+504 
+Change in fair value of contingent consideration 
+25 
+(181 
+) 
+(619 
+) 
+Total operating expenses 
+23,950 
+21,624 
+21,054 
+Operating income 
+2,024 
+1,634 
+2,017 
+Non-operating income (expense): 
+Other income (expense), net 
+— 
+2 
+4 
+Interest income (expense), net 
+— 
+(6 
+) 
+(72 
+) 
+Income from continuing operations before income taxes 
+2,024 
+1,630 
+1,949 
+Provision for income taxes 
+(704 
+) 
+(716 
+) 
+(643 
+) 
+Income from continuing operations 
+1,320 
+914 
+1,306 
+Gain on sale of discontinued operation, net of tax 
+89 
+1,465 
+1,180 
+Income from discontinued operation, net of tax 
+— 
+— 
+28 
+Net income 
+$ 
+1,409 
+$ 
+2,379 
+$ 
+2,514 
+Income per share from continuing operations—basic and diluted 
+$ 
+0.04 
+$ 
+0.03 
+$ 
+0.04 
+Gain per share from sale of discontinued operation—basic and diluted 
+$ 
+0.00 
+$ 
+0.04 
+$ 
+0.03 
+Income per share from discontinued operation—basic and diluted 
+$ 
+0.00 
+$ 
+0.00 
+$ 
+0.00 
+Net income per share—basic and diluted 
+$ 
+0.04 
+$ 
+0.07 
+$ 
+0.07 
+Shares used in basic per share calculations 
+32,665 
+33,491 
+34,259 
+Shares used in diluted per share calculations 
+32,847 
+33,609 
+34,380 
+See accompanying notes. 
+59 
+Table of Contents 
+Iteris, Inc. 
+Consolidated Statements of Stockholders' Equity 
+(In thousands) 
+Common Stock 
+Additional 
+Paid-In 
+Capital 
+Accumulated 
+Deficit 
+Total 
+Stockholders' 
+Equity 
+Shares 
+Amount 
+Balance at March 31, 2011 
+34,364 
+$ 
+3,436 
+$ 
+137,938 
+$ 
+(88,078 
+) 
+$ 
+53,296 
+Stock option exercises 
+68 
+8 
+77 
+— 
+85 
+Stock-based compensation 
+— 
+— 
+331 
+— 
+331 
+Issuance of shares pursuant to vesting of restricted stock units 
+51 
+5 
+(5 
+) 
+— 
+— 
+Repurchases of common stock 
+(574 
+) 
+(58 
+) 
+(696 
+) 
+— 
+(754 
+) 
+Net income 
+— 
+— 
+— 
+2,514 
+2,514 
+Balance at March 31, 2012 
+33,909 
+3,391 
+137,645 
+(85,564 
+) 
+55,472 
+Stock option exercises 
+190 
+20 
+232 
+— 
+252 
+Stock-based compensation 
+— 
+— 
+279 
+— 
+279 
+Issuance of shares pursuant to vesting of restricted stock units 
+51 
+5 
+(29 
+) 
+— 
+(24 
+) 
+Repurchases of common stock 
+(1,524 
+) 
+(152 
+) 
+(2,325 
+) 
+— 
+(2,477 
+) 
+Net income 
+— 
+— 
+— 
+2,379 
+2,379 
+Balance at March 31, 2013 
+32,626 
+3,264 
+135,802 
+(83,185 
+) 
+55,881 
+Stock option exercises 
+284 
+27 
+228 
+— 
+255 
+Warrant exercises 
+15 
+2 
+13 
+— 
+15 
+Stock-based compensation 
+— 
+— 
+300 
+— 
+300 
+Issuance of shares pursuant to vesting of restricted stock units 
+59 
+6 
+(37 
+) 
+— 
+(31 
+) 
+Repurchases of common stock 
+(196 
+) 
+(19 
+) 
+(320 
+) 
+— 
+(339 
+) 
+Net income 
+— 
+— 
+— 
+1,409 
+1,409 
+Balance at March 31, 2014 
+32,788 
+$ 
+3,280 
+$ 
+135,986 
+$ 
+(81,776 
+) 
+$ 
+57,490 
+See accompanying notes. 
+60 
+Table of Contents 
+Iteris, Inc. 
+Consolidated Statements of Cash Flows 
+(In thousands) 
+Year Ended March 31, 
+2014 
+2013 
+2012 
+Cash flows from operating activities 
+Net income 
+$ 
+1,409 
+$ 
+2,379 
+$ 
+2,514 
+Adjustments to reconcile net income to net cash provided by operating activities: 
+Deferred income taxes 
+710 
+1,414 
+286 
+Depreciation of property and equipment 
+768 
+901 
+907 
+Stock-based compensation 
+300 
+279 
+331 
+Amortization of intangible assets 
+733 
+644 
+504 
+Change in fair value of contingent consideration 
+25 
+(181 
+) 
+(619 
+) 
+Gain on sale of discontinued operation, net of tax 
+(89 
+) 
+(1,465 
+) 
+(1,180 
+) 
+Loss on disposal of equipment 
+— 
+— 
+1 
+Loss on impairment of intangible asset 
+108 
+— 
+— 
+Changes in operating assets and liabilities, net of effects of discontinued operation: 
+Accounts receivable 
+(1,403 
+) 
+135 
+(1,826 
+) 
+Net costs and estimated earnings in excess of billings 
+(34 
+) 
+(570 
+) 
+(902 
+) 
+Inventories 
+(81 
+) 
+(11 
+) 
+79 
+Prepaid expenses and other assets 
+140 
+(793 
+) 
+284 
+Accounts payable and accrued expenses 
+688 
+461 
+289 
+Net cash provided by operating activities 
+3,274 
+3,193 
+668 
+Cash flows from investing activities 
+Purchases of property and equipment 
+(452 
+) 
+(815 
+) 
+(337 
+) 
+Capitalized software 
+(301 
+) 
+(190 
+) 
+(138 
+) 
+Cash paid for business combination 
+— 
+— 
+(969 
+) 
+Net proceeds from sale of business segment 
+(26 
+) 
+1,372 
+11,446 
+Net cash (used in) provided by investing activities 
+(779 
+) 
+367 
+10,002 
+Cash flows from financing activities 
+Payments on long-term debt 
+— 
+(634 
+) 
+(2,330 
+) 
+Deferred payment for prior business combination 
+(659 
+) 
+(700 
+) 
+(788 
+) 
+Repurchases of common stock 
+(339 
+) 
+(2,477 
+) 
+(754 
+) 
+Proceeds from stock option exercises 
+270 
+252 
+85 
+Issuance of common stock pursuant to restricted stock units 
+(31 
+) 
+(24 
+) 
+— 
+Net cash used in financing activities 
+(759 
+) 
+(3,583 
+) 
+(3,787 
+) 
+Increase (decrease) in cash and cash equivalents 
+1,736 
+(23 
+) 
+6,883 
+Cash and cash equivalents at beginning of period 
+18,678 
+18,701 
+11,818 
+Cash and cash equivalents at end of period 
+$ 
+20,414 
+$ 
+18,678 
+$ 
+18,701 
+Supplemental cash flow information: 
+Cash paid during the year for: 
+Interest 
+$ 
+33 
+$ 
+45 
+$ 
+111 
+Income taxes 
+128 
+339 
+439 
+Supplemental schedule of non-cash investing and financing activities: 
+Liabilities incurred for business combinations 
+$ 
+— 
+$ 
+— 
+$ 
+971 
+Issuance of common stock for vested restricted stock units 
+6 
+5 
+5 
+See accompanying notes. 
+61 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements 
+March 31, 2014 
+1. Description of Business and Summary of Significant Accounting Policies 
+Description of Business 
+Iteris, Inc. (referred to collectively with our subsidiaries in these consolidated financial statements as "Iteris," the
+"Company," "we," "our" and "us") is a leading provider of intelligent information solutions for the traffic management market. We are focused on the development and application of advanced
+technologies and software-based information systems that reduce traffic congestion, provide measurement, management and predictive traffic analytics and improve the safety of surface transportation
+systems infrastructure. We also believe our products, services and solutions, in conjunction with sound traffic management, minimize the environmental impact of traffic congestion. By combining our
+unique intellectual property, products, decades of experience in traffic management, hyper-local weather solutions and information technologies, we offer
+a broad range of Intelligent Transportation Systems ("ITS") solutions to customers throughout the U.S. and internationally. Iteris was incorporated in Delaware in 1987. 
+Basis of Presentation 
+Our consolidated financial statements include the accounts of Iteris, Inc. and its subsidiaries and have been prepared in
+accordance with accounting principles generally accepted in the United States of America ("GAAP"). All significant intercompany accounts and transactions have been eliminated in consolidation. 
+The
+results of continuing operations for all periods presented in the consolidated financial statements exclude the financial impact of discontinued operations. See Note 3, "Sale
+of Vehicle Sensors", for further discussion related to discontinued operations presentation. 
+Use of Estimates 
+The preparation of consolidated financial statements in conformity with GAAP requires our management to make certain estimates and
+assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements, and reported amounts of revenues
+and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates made in the preparation of the consolidated financial statements include the
+collectability of accounts receivable, the valuation of inventories, the recoverability of long-lived assets and goodwill, the realizability of deferred tax assets, accounting for stock-based
+compensation, the valuation of equity instruments, the valuation of contingent acquisition consideration, warranty reserves and other contingencies. 
+Revenue Recognition 
+Product revenues and related costs of sales are recognized when all of the following criteria are met: (i) persuasive evidence
+of an arrangement exists, (ii) delivery under the terms of the arrangement has occurred, (iii) the price to the customer is fixed or determinable, and (iv) collection of the
+receivable is reasonably assured. These criteria are typically met at the time of product shipment, but in certain circumstances, may not be met until receipt or acceptance by the
+customer. Accordingly, at the date revenue is recognized, the significant obligations or uncertainties concerning the sale have been resolved. 
+62 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+1. Description of Business and Summary of Significant Accounting Policies (Continued) 
+Transportation
+Systems and iPerform revenues are derived primarily from long-term contracts with governmental agencies. When appropriate, revenues are recognized using the percentage of
+completion method of accounting, whereby revenue is recognized as contract performance progresses and is determined based on the relationship of costs incurred to total estimated costs. Any
+anticipated losses on contracts are charged to earnings when identified. Changes in job performance and estimated profitability, including those arising from contract penalty provisions and final
+contract settlements, may result in revisions to costs and revenues and are recognized in the period in which the revisions are determined. Profit incentives are included in revenues when their
+realization is reasonably assured. Certain of our revenues are recognized as services are performed and amounts are earned, which is measured by time incurred or other contractual milestones or output
+measures. Revenues accounted for in this manner generally relate to certain fixed fee professional services, cost-plus fixed fee or time-and-materials contracts. Revenues for ongoing operations and
+maintenance services contracts are generally accounted for ratably as the services are performed throughout the term of the contract. Payments received in advance of services performed are deferred
+and recognized when the related services are performed. 
+We
+recognize revenue from the sale of deliverables that are part of a multiple-element arrangement in accordance with applicable accounting guidance that establishes a relative selling
+price hierarchy permitting the use of an estimated selling price to determine the allocation of arrangement consideration to a deliverable in a multiple-element arrangement where neither vendor
+specific objective evidence ("VSOE") nor third-party evidence ("TPE") of fair value is available for that deliverable. In the absence of VSOE or TPE of the standalone selling price for one or more
+delivered or undelivered elements in a multiple-element arrangement, we are required to estimate the selling prices of those elements. Overall arrangement consideration is allocated to each element
+(both delivered and undelivered items) that has stand-alone value based on their relative selling prices, regardless of whether those selling prices are evidenced by VSOE or TPE or are based on our
+estimated selling prices. 
+We
+account for multiple-element arrangements that consist only of software and software-related services in accordance with applicable accounting guidance for software and
+software-related transactions. For such transactions, revenue on arrangements that include multiple elements is allocated to each element based on the relative fair value of each element, and fair
+value is determined by VSOE. If we cannot objectively determine the fair value of any undelivered element included in such multiple-element arrangements and the only undelivered element is
+post-contract customer support or maintenance, and VSOE of the fair value of such support or maintenance does not exist, revenue from the entire arrangement is recognized ratably over the support
+period. When the fair value of a delivered element has not been established but VSOE of fair value exists for the undelivered elements, we use the residual method to recognize revenue if the fair
+value of all undelivered elements is
+determinable. Under the residual method, the fair value of the undelivered elements is deferred and the remaining portion of the arrangement fee is allocated to the delivered elements and is
+recognized as revenue. 
+63 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+1. Description of Business and Summary of Significant Accounting Policies (Continued) 
+Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts 
+Costs and estimated earnings in excess of billings on uncompleted contracts in the accompanying consolidated balance sheets represent
+unbilled amounts earned and reimbursable under services sales arrangements. At any given period-end, a large portion of the balance in this account represents the accumulation of labor, materials and
+other costs that have not been billed due to timing, whereby the accumulation of each month's costs and earnings are not administratively billed until the subsequent month. Also included in this
+account are amounts that will become billable according to contract terms, which usually require the consideration of the passage of time, achievement of milestones or completion of the project. Such
+unbilled amounts are expected to be billed and collected within the next twelve months. 
+Costs
+and estimated earnings in excess of billings on uncompleted contracts at March 31, 2014 and 2013 include approximately $1,064,000 and $937,000, respectively, which were not
+billable because certain milestone objectives specified in the contracts had not been attained. The costs and estimated earnings in excess of billings at March 31, 2014 are expected to be
+billed and collected during the fiscal year ending March 31, 2015 ("Fiscal 2015"). 
+Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts 
+Billings in excess of costs and estimated earnings on uncompleted contracts in the accompanying consolidated balance sheets is
+comprised of cash collected from customers and billings to customers on contracts in advance of work performed, advance payments negotiated as a contract condition, estimated losses on uncompleted
+contracts, project-related legal liabilities and other project-related reserves. The unearned amounts are expected to be earned within the next twelve months. 
+We
+record provisions for estimated losses on uncompleted contracts in the period in which such losses become known. The cumulative effects of revisions to contract revenues and estimated
+completion costs are recorded in the accounting period in which the amounts become evident and can be reasonably estimated. These revisions can include such items as the effects of change orders and
+claims, warranty claims, liquidated damages or other contractual penalties and adjustments for audit findings on contract closeout settlements. 
+Concentration of Credit Risk 
+Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash and cash equivalents
+and trade accounts receivable. 
+Cash
+and cash equivalents consist primarily of demand deposits and money market funds maintained with several financial institutions. Deposits held with banks may exceed the amount of
+insurance provided on such deposits. Generally, these deposits may be redeemed upon demand and are maintained with high credit quality financial institutions and therefore are believed to have minimal
+credit risk. 
+Our
+accounts receivable are primarily derived from billings with customers located throughout North America, as well as in the Middle East, Europe, South America and Asia. We generally
+do not 
+64 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+1. Description of Business and Summary of Significant Accounting Policies (Continued) 
+require
+collateral or other security from customers. We maintain an allowance for doubtful accounts for potential credit losses, which losses have historically been within management's expectations. 
+Fair Values of Financial Instruments 
+The fair value of cash and cash equivalents, receivables, accounts payable and accrued expenses approximate carrying value because of
+the short period of time to maturity. The fair value of line of credit agreements and long-term debt approximate carrying value because the
+related effective rates of interest approximate current market rates available to us for debt with similar terms and similar remaining maturities. 
+Cash and Cash Equivalents 
+Cash and cash equivalents consist of cash and short-term investments with initial maturities of ninety days or less. Prior year cash
+and cash equivalents have been reclassed to conform with current year presentation. 
+Allowance for Doubtful Accounts 
+The collectability of our accounts receivable is evaluated through review of outstanding invoices and ongoing credit evaluations of our
+customers' financial condition. In cases where we are aware of circumstances that may impair a specific customer's ability to meet its financial obligations subsequent to the original sale, we will
+record an allowance against amounts due, and thereby reduce the net recognized receivable to the amount we reasonably believe will be collected. We also maintain an allowance based on our historical
+collections experience. When we determine that collection is not likely, we write off accounts receivable against the allowance for doubtful accounts. 
+Inventories 
+Inventories consist of finished goods, work-in-process and raw materials and are stated at the lower of cost or market. Cost is
+determined using the first-in, first-out method. 
+Property and Equipment 
+Property and equipment are recorded at cost and are depreciated using the straight-line method over the estimated useful life ranging
+from three to eight years. Leasehold improvements are depreciated over the term of the related lease or the estimated useful life of the improvement, whichever is shorter. 
+Goodwill and Long-Lived Assets 
+We evaluate goodwill on an annual basis in our fourth fiscal quarter or more frequently if we believe indicators of impairment exist.
+We have determined that our reporting units for purposes of testing for goodwill impairment are identical to our reportable segments for financial reporting purposes. In the fiscal year ended
+March 31, 2012 ("Fiscal 2012"), we adopted the provisions issued by the Financial Accounting Standards Board ("FASB") that were intended to simplify goodwill impairment testing. This guidance
+permits us to first assess qualitative factors to determine whether it 
+65 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+1. Description of Business and Summary of Significant Accounting Policies (Continued) 
+is
+more likely than not that the fair value of a reporting unit is less than its carrying amount. If we conclude that it is more likely than not that the fair value of a reporting unit is less than
+its carrying amount, we conduct a two-step goodwill impairment test. The first step of the impairment test involves comparing the fair values of the applicable reporting units with their carrying
+values. We determine the fair values of our reporting units using the income valuation approach, as well as other generally accepted valuation methodologies. If the carrying amount of a reporting unit
+exceeds the reporting unit's fair value, we perform the second step of the goodwill impairment test. The second step of the goodwill impairment test involves comparing the implied fair value of the
+affected reporting unit's goodwill with the carrying value of that goodwill. The amount by which the carrying value of the goodwill exceeds its implied fair value, if any, is recognized as an
+impairment loss. We performed an annual impairment assessment of the carrying value of goodwill for each of the fiscal years ended March 31, 2014, 2013 and 2012. Based on these assessments, we
+determined that no impairment as of each of these dates was indicated as the estimated fair value of each of our reporting units exceeded its respective carrying value. We monitor the indicators for
+goodwill impairment testing between annual tests. Certain adverse business conditions impacting one or more reporting units would cause us to test goodwill for impairment on an interim basis. 
+We
+test long-lived assets and purchased intangible assets (other than goodwill) for impairment if we believe indicators of impairment exist. We determine whether the carrying value of an
+asset or asset group is recoverable, based on comparisons to undiscounted expected future cash flows the asset are expected to generate. If an asset is not recoverable, we record an impairment loss
+equal to the amount by which the carrying value of the asset exceeds its fair value. We primarily use the income valuation approach to determine the fair value of our long lived assets and purchased
+intangible assets. 
+Income Taxes 
+We utilize the asset and liability method of accounting for income taxes, under which deferred taxes are determined based on the
+temporary differences between the financial statement and tax basis of assets and liabilities using tax rates expected to be in effect during the years in which the basis differences reverse. A
+valuation allowance is recorded when it is more-likely-than-not that some or all of the deferred tax assets will not be realized, which increases our income tax expense in the period such
+determination is made. 
+Income
+tax positions must meet a more-likely-than-not recognition threshold to be recognized. Income tax positions that previously failed to meet the more-likely-than-not threshold are
+recognized in the first subsequent financial reporting period in which that threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not threshold are
+derecognized in the first subsequent financial reporting period in which that threshold is no longer met. 
+Stock-Based Compensation 
+We record stock-based compensation in the consolidated statement of operations as an expense, based on the estimated grant date fair
+value of our stock-based awards, whereby such fair values are amortized over the requisite service period. Our stock-based awards are currently comprised of common stock options and restricted stock
+units. The fair value of our common stock option awards is estimated on the grant date using the Black-Scholes-Merton ("BSM") option-pricing formula. While 
+66 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+1. Description of Business and Summary of Significant Accounting Policies (Continued) 
+utilizing
+this model meets established requirements, the estimated fair values generated by it may not be indicative of the actual fair values of our common stock option awards as it does not consider
+certain factors important to those awards to employees, such as continued employment and periodic vesting requirements as well as limited transferability. The fair value of our restricted stock units
+is based on the closing market price of our common stock on the grant date. If there are any modifications or cancellations of the underlying unvested stock-based awards, we may be required to
+accelerate, increase or cancel any remaining unearned stock-based compensation expense. 
+Research and Development Expenditures 
+Research and development expenditures are charged to expense in the period incurred. 
+Shipping and Handling Costs 
+Shipping and handling costs are included as cost of revenues in the period during which the products ship. 
+Sales Taxes 
+Sales taxes are presented on a net basis (excluded from revenues) in the consolidated statements of operations. 
+Advertising Expenses 
+Advertising costs are expensed in the period incurred and totaled $168,000, $165,000 and $187,000 in the fiscal years ended
+March 31, 2014, 2013 and 2012, respectively. 
+Warranty 
+We generally provide a one to three year warranty from the original invoice date on all products, materials and workmanship. Products
+sold to various original equipment manufacturer customers sometimes carry longer warranties. Defective products will be either repaired or replaced, usually at our option, upon meeting certain
+criteria. We accrue a provision for the
+estimated costs that may be incurred for product warranties relating to a product as a component of cost of sales at the time revenue for that product is recognized. The accrued warranty reserve is
+included within accrued liabilities in the accompanying consolidated balance sheets. 
+Repair and Maintenance Costs 
+We incur repair and maintenance costs in the normal course of business. Should the repair or maintenance result in a permanent
+improvement to one of our leased facilities, the cost is capitalized as a leasehold improvement and amortized over its useful life or the remainder of the lease period, whichever is shorter.
+Non-permanent repair and maintenance costs are charged to expense as incurred. 
+Comprehensive Income 
+Comprehensive income equals net income for all periods presented. 
+67 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+1. Description of Business and Summary of Significant Accounting Policies (Continued) 
+Recent Accounting Pronouncements 
+In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with
+Customers ("ASU 2014-09"), which supersedes the revenue recognition requirements in Accounting Standards Codification 605, Revenue
+Recognition . ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the
+consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and
+uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgment and assets recognized from costs incurred to obtain or fulfill a
+contract. The effective date will be the first quarter of our fiscal year ending March 31, 2018, using one of two retrospective application methods. The Company has not determined the potential
+effects on the consolidated financial statements. 
+2. Supplementary Financial Information 
+Inventories 
+The following table presents details regarding our inventories: 
+March 31, 
+2014 
+2013 
+(In thousands) 
+Materials and supplies 
+$ 
+1,320 
+$ 
+1,504 
+Work in process 
+175 
+105 
+Finished goods 
+1,051 
+856 
+$ 
+2,546 
+$ 
+2,465 
+Property and Equipment 
+The following table presents details of our property and equipment: 
+March 31, 
+2014 
+2013 
+(In thousands) 
+Equipment 
+$ 
+6,541 
+$ 
+6,126 
+Leasehold improvements 
+1,975 
+1,953 
+Accumulated depreciation 
+(6,970 
+) 
+(6,217 
+) 
+$ 
+1,546 
+$ 
+1,862 
+Depreciation
+expense was approximately $768,000 and $901,000 in the fiscal year ended March 31, 2014 ("Fiscal 2014") and the fiscal year ended March 31, 2013 ("Fiscal
+2013"), respectively. 
+68 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+2. Supplementary Financial Information (Continued) 
+Intangible Assets 
+The following table presents details regarding our intangible assets: 
+March 31, 
+2014 
+2013 
+Gross 
+Carrying 
+Amount 
+Accumulated 
+Amortization 
+Gross 
+Carrying 
+Amount 
+Accumulated 
+Amortization 
+(In thousands) 
+Technology 
+$ 
+1,856 
+$ 
+(1,422 
+) 
+$ 
+1,856 
+$ 
+(1,178 
+) 
+Customer contracts / relationships 
+750 
+(371 
+) 
+750 
+(247 
+) 
+Trade names and non-compete agreements 
+1,110 
+(754 
+) 
+1,110 
+(495 
+) 
+Capitalized software development costs 
+498 
+(83 
+) 
+328 
+— 
+Total 
+$ 
+4,214 
+$ 
+(2,630 
+) 
+$ 
+4,044 
+$ 
+(1,920 
+) 
+Amortization
+expense for intangible assets subject to amortization was approximately $733,000 for Fiscal 2014, of which approximately $106,000 was recorded to cost of revenues and
+approximately $627,000 recorded to amortization expense in the consolidated statement of operations. Approximately $644,000 and $504,000 was recorded to amortization expense for the fiscal years ended
+March 31, 2013 and 2012, respectively. 
+We
+capitalized approximately $172,000 and $190,000 for the fiscal years ended March 31, 2014 and 2013, respectively, of internal costs incurred in developing software products to
+be sold. These costs related to the internal development of our performance measurement software offerings. During the fourth quarter of the fiscal year ended March 31, 2014, we recognized a
+loss on impairment of intangible assets related to capitalized software of approximately $108,000. 
+Capitalized
+software development costs for the iPeMS platform and acquired data sets began to be amortized in October 2013, resulting in approximately $106,000 recorded to cost of
+revenues in the accompanying consolidated statement of operations for the year ended March 31, 2014. We do not have any intangible assets with indefinite useful lives. As of March 31,
+2014, the future estimated amortization expense of approximately $1.6 million is entirely associated with our iPerform business segment, as follows: 
+Year Ending March 31,
+(In thousands) 
+2015 
+$ 
+597 
+2016 
+526 
+2017 
+365 
+2018 
+88 
+2019 
+8 
+Thereafter 
+— 
+$ 
+1,584 
+69 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+2. Supplementary Financial Information (Continued) 
+Refer
+to Note 4 for additional information regarding intangible assets acquired during the last three fiscal years. If we acquire additional intangible assets in future periods,
+our future amortization expense will increase. 
+Goodwill 
+The following table presents the activity related to the carrying value of our goodwill by reportable segment for Fiscal 2012, Fiscal
+2013 and Fiscal 2014: 
+Roadway 
+Sensors 
+Transportation 
+Systems 
+iPerform 
+Total 
+(In thousands) 
+Balance—March 31, 2012 
+Goodwill 
+8,214 
+17,074 
+— 
+25,288 
+Accumulated impairment losses 
+— 
+(7,970 
+) 
+— 
+(7,970 
+) 
+$ 
+8,214 
+$ 
+9,104 
+$ 
+— 
+$ 
+17,318 
+Balance—March 31, 2013 
+Goodwill 
+8,214 
+16,278 
+796 
+25,288 
+Accumulated impairment losses 
+— 
+(7,970 
+) 
+— 
+(7,970 
+) 
+8,214 
+8,308 
+796 
+17,318 
+Balance—March 31, 2014 
+Goodwill 
+8,214 
+14,906 
+2,168 
+25,288 
+Accumulated impairment losses 
+— 
+(7,970 
+) 
+— 
+(7,970 
+) 
+$ 
+8,214 
+$ 
+6,936 
+$ 
+2,168 
+$ 
+17,318 
+In
+Fiscal 2013, the Company established the iPerform segment, which included the performance measurement and information management solutions, including all the operations of Berkeley
+Transportation Systems, Inc. ("BTS"). As a result, the goodwill attributed to the BTS acquisition of approximately $796,000 was transferred to the newly created iPerform segment. 
+In
+the first quarter of Fiscal 2014, as part of an internal reorganization, the Company's ClearPath Weather operations (formerly, Maintenance Decision Support System or MDSS),
+historically included in the Transportation Systems segment, was reassigned to the iPerform segment to better align the Company's predictive weather and traffic capabilities, resources, and
+initiatives. As a result, the goodwill attributed to the ClearPath Weather operations from the Meridian Environmental Technology, Inc. ("MET") acquisition of approximately $1,372,000 was
+transferred to the iPerform segment. 
+70 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+2. Supplementary Financial Information (Continued) 
+Warranty Reserve Activity 
+The following table presents activity with respect to the warranty reserve: 
+Year Ended March 31, 
+2014 
+2013 
+2012 
+(In thousands) 
+Balance at beginning of fiscal year 
+$ 
+169 
+$ 
+231 
+$ 
+279 
+Additions charged to cost of sales 
+179 
+139 
+86 
+Warranty claims 
+(164 
+) 
+(201 
+) 
+(134 
+) 
+Balance at end of fiscal year 
+$ 
+184 
+$ 
+169 
+$ 
+231 
+Earnings Per Share 
+The following table sets forth the computation of basic and diluted income from continuing operations per share: 
+Year Ended March 31, 
+2014 
+2013 
+2012 
+(In thousands, except per share amounts) 
+Numerator: 
+Income from continuing operations 
+$ 
+1,320 
+$ 
+914 
+$ 
+1,306 
+Denominator: 
+Weighted average common shares used in basic computation 
+32,665 
+33,491 
+34,259 
+Dilutive stock options 
+111 
+60 
+96 
+Dilutive restricted stock units 
+70 
+56 
+25 
+Dilutive warrants 
+1 
+2 
+— 
+Weighted average common shares used in diluted computation 
+32,847 
+33,609 
+34,380 
+Income from continuing operations per share: 
+Basic 
+$ 
+0.04 
+$ 
+0.03 
+$ 
+0.04 
+Diluted 
+$ 
+0.04 
+$ 
+0.03 
+$ 
+0.04 
+The
+following instruments were excluded for purposes of calculating weighted average common share equivalents in the computation of diluted income from continuing operations per share as
+their effect would have been anti-dilutive: 
+Year Ended March 31, 
+2014 
+2013 
+2012 
+(In thousands) 
+Stock options 
+854 
+1,049 
+1,840 
+Warrants 
+— 
+4 
+15 
+71 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+3. Sale of Vehicle Sensors 
+On July 29, 2011, we completed the sale of substantially all of our assets used in connection with our Vehicle Sensors segment to Bendix Commercial Vehicle Systems LLC
+("Bendix"), a member of Knorr-Bremse Group, pursuant to an Asset Purchase Agreement (the "Agreement") signed on July 25, 2011 (the "Asset Sale"). 
+Under
+the terms of the Agreement, upon the closing of the Asset Sale, Bendix paid us $14 million in cash, subject to a $2 million holdback and adjustments based upon the
+working capital of the Vehicle Sensors segment at closing, and Bendix assumed certain specified obligations and liabilities of the Vehicle Sensors segment. In October 2012, we received approximately
+$1.7 million in connection with the holdback provision. Furthermore, we are entitled to additional consideration in the form of the following performance and royalty-related earn-outs: Bendix
+is obligated to pay us an amount in cash equal to (i) 85% of revenue associated with royalties received under our license and distribution agreements with Audiovox Electronics Corporation and
+Valeo Schalter and Sensoren GmbH through December 31, 2017 and (ii) 30% of the amount, if any, by which the amount of revenue generated from the sale of our lane departure warning
+systems exceeds Bendix's projection for such revenue for the two years following closing, each subject to certain reductions and limitations set forth in the Agreement. As of March 31, 2014, we
+received approximately $1.1 million in connection with royalty-related earn-outs provisions for a total of $14.8 million in cash from the Asset Sale. 
+Upon
+the closing of the Asset Sale and resolution of working capital adjustments (as described above), we recorded aggregate proceeds received of approximately $12.0 million.
+Legal and other professional fees of approximately $0.6 million that were directly related to the sale transaction were offset against the proceeds to calculate net proceeds from the Asset Sale
+of approximately $11.4 million. 
+The
+following table summarizes the assets and liabilities of the Vehicle Sensors segment as of the closing date of the Asset Sale (in thousands): 
+Cash 
+$ 
+105 
+Accounts receivable 
+1,850 
+Inventories 
+1,147 
+Other current assets 
+31 
+Property and equipment, net 
+133 
+Goodwill 
+4,671 
+Total assets 
+7,937 
+Current liabilities 
+(691 
+) 
+Net assets 
+$ 
+7,246 
+In
+comparing the above net assets to the net proceeds received, we recorded a gain on the Asset Sale of $89,000, $1.5 million, and $1.2 million, after tax, in the
+accompanying consolidated statements of operations for Fiscal 2014, Fiscal 2013, and Fiscal 2012, respectively. The $89,000 gain on the Asset Sale in Fiscal 2014 is related to certain performance and
+royalty-related earn-outs (as described above) that were achieved through March 31, 2014. Included in the $1.5 million gain on the Asset Sale in Fiscal 2013 was an accrual for
+approximately $90,000, or $58,000 after tax, related to certain performance and royalty-related earn-outs that were achieved through March 31, 2013. The effective 
+72 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+3. Sale of Vehicle Sensors (Continued) 
+tax
+rate applicable to the gain was impacted by goodwill of $4.7 million for Fiscal 2012, for which there is no corresponding tax basis. 
+In
+accordance with applicable accounting guidance, we determined that the Vehicle Sensors segment, which constituted one of our operating segments, qualified as a discontinued operation.
+The applicable financial results of the Vehicle Sensors segment have been reported as a discontinued operation in the consolidated statements of operations for all periods presented. For the fiscal
+years ended March 31, 2014, 2013 and 2012, Vehicle Sensors net sales classified as part of discontinued operation was $0, $0 and $3.2 million, respectively. We elected not to allocate
+any interest expense to the discontinued operation. 
+We
+entered into a short-term transitional services agreement with Bendix that terminated at the end of February 2012, pursuant to which we provided them certain ongoing logistical and
+administrative support services. Bendix paid us a fixed monthly amount for such support services, and also paid us an hourly amount for providing certain development-related services during the
+transition period. 
+4. Acquisitions 
+Berkeley Transportation Systems, Inc. 
+In November 2011, we acquired all of the outstanding capital stock of Berkeley Transportation Systems, Inc. ("BTS"). BTS was a
+privately-held company based in Berkeley, California, which specializes in transportation performance measurement. BTS' Performance Measurement System leverages its real-time data collection,
+diagnostic, fusion and warehousing platform to aggregate and compute performance measures. This information is used to analyze how a transportation system is performing based on pre-determined
+measures of effectiveness such as stops, delays and travel time. Our primary reasons for the acquisition were to add key technologies to complement our iPerform solutions and strengthen our
+performance measurement and management initiative as a whole. 
+Our
+consolidated financial statements for Fiscal 2014, Fiscal 2013 and Fiscal 2012 include the results of operations of BTS commencing as of the acquisition date. On or shortly after the
+acquisition date, we paid a total of approximately $840,000 in cash to BTS. During the third quarter of Fiscal 2014, the Company paid $250,000 pursuant to certain holdback provisions. Additionally,
+the Company is scheduled to pay to the BTS shareholders up to approximately $335,000 by November 2014 pursuant to certain deferred payment provision. On December 17, 2012, the Company entered
+into an amendment to the BTS stock purchase agreement which modified certain earn-out provisions, and as a result, the Company paid $700,000 in cash to the BTS shareholders for achievement of those
+modified earn-out provisions in our fourth quarter of Fiscal 2013. The amendment did not have a material impact on previous estimated amounts accrued in connection with the earn-out provisions. This
+payment completed the Company's obligation under the earn-out provisions of the agreement. 
+Acquisition Accounting 
+We accounted for the acquisition of BTS as a business combination in accordance with applicable accounting guidance. We measured the
+fair value of the consideration transferred (including contingent consideration) to determine the purchase price of the acquisition. We allocated the fair value of 
+73 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+4. Acquisitions (Continued) 
+consideration
+transferred to tangible assets acquired, liabilities assumed and identifiable intangible assets acquired based on their estimated fair values at the acquisition date. 
+The
+BTS acquisition was recorded as follows (in thousands): 
+Fair value of consideration transferred: 
+Cash paid on or shortly after acquisition date 
+$ 
+840 
+Estimated fair value of contingent consideration 
+971 
+Total 
+1,811 
+Allocation: 
+Accounts receivable 
+(164 
+) 
+Other tangible assets 
+(375 
+) 
+Purchased intangible assets 
+(1,100 
+) 
+Liabilities 
+624 
+Goodwill 
+$ 
+796 
+The
+excess of the fair value of the BTS business over the aggregate fair values of identifiable assets acquired and liabilities assumed was recorded as goodwill. The primary factor that
+resulted in the recognition of goodwill was the acquisition of BTS' assembled workforce, which is not a separately identifiable intangible asset. The goodwill is not deductible for income tax
+purposes. 
+Purchased Intangible Assets 
+The following table presents details of the intangible assets acquired from BTS: 
+Estimated 
+Useful Life 
+Amount 
+(In years) 
+(In thousands) 
+Backlog 
+3 
+$ 
+330 
+Technology 
+6 
+290 
+Customer contracts / relationships 
+6 
+250 
+Other purchased intangible assets 
+5 - 7 
+230 
+$ 
+1,100 
+Meridian Environmental Technology, Inc. 
+In January 2011, we acquired all of the capital stock of Meridian Environmental Technology, Inc. ("MET"), a privately-held
+company based in Grand Forks, North Dakota. MET specializes in 511 advanced traveler information systems, as well as Maintenance Decision Support System management tools that allow users to create
+solutions to meet roadway maintenance decision needs. Our primary reasons for the acquisition were (i) to enhance our ability to provide travelers and traffic management authorities with more
+accurate and real-time information and network performance management tools and (ii) to provide Iteris with key capabilities in the emerging performance measurement and management market. 
+74 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+4. Acquisitions (Continued) 
+On
+or shortly after the acquisition date, we paid approximately $1.6 million in cash, exclusive of $369,000 of cash acquired. We also agreed to pay up to $1 million on each
+of the first two anniversaries of the closing of the acquisition upon the satisfaction of certain conditions, as well as up to an additional $2 million under a 24-month earn-out provision. 
+In
+January 2012, we made a cash payment of approximately $668,000 of the first deferred payment to the shareholders of MET and held back $250,000 in accordance with certain provisions of
+the purchase agreement. In June 2012, we determined the contingencies related to the release of the $250,000 holdback were not met. As a result, no portion of the $250,000 holdback was released and
+the entire amount was reversed into operating income during the second quarter of Fiscal 2013. Additionally, no amounts were earned by the MET shareholders related to the first and second year
+earn-out provisions which ended on December 31, 2011 and 2012, respectively. The second deferred payment of $1 million was due in the fourth quarter of Fiscal 2013. As a result of
+certain holdback provisions and other deductions, the Company paid approximately $409,000 to the MET shareholders in the second quarter of Fiscal 2014. This payment completed the Company's obligation
+under the deferred payment provisions of the purchase agreement. 
+Purchased Intangible Assets 
+The following table presents details of the intangible assets acquired from MET: 
+Estimated 
+Useful Life 
+Amount 
+(In years) 
+(In thousands) 
+Technology 
+6 
+$ 
+570 
+Customer contracts / relationships 
+6 
+500 
+Other purchased intangible assets 
+3 - 7 
+550 
+$ 
+1,620 
+5. Impairment of Goodwill 
+As discussed in Note 1, goodwill is tested for impairment on an annual basis in our fourth fiscal quarter or more frequently if indicators of impairment exist. 
+In
+Fiscal 2012, we early adopted the provisions issued by the FASB that are intended to simplify goodwill impairment testing. The updated guidance permits us to first assess qualitative
+factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If we conclude that it is more likely than not that the fair value of
+a reporting units is less than its carrying amount, we conduct a two-step goodwill impairment test. We determined it was more appropriate to perform a qualitative assessment in Fiscal 2012 and a
+quantitative first-step assessment in Fiscal 2013 and Fiscal 2014 to estimate the fair value of our reporting units using both the income approach and the market approach. Based on our assessments, we
+determined that no impairment was indicated as the estimated fair value of each reporting unit exceeded its respective carrying value. 
+75 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+6. Fair Value Measurements 
+We measure fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset
+or liability in an orderly transaction between market participants on the measurement date. Fair value measurements are based on a three-tier hierarchy that prioritizes the inputs used to measure fair
+value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets for identical assets and liabilities; Level 2, defined as observable inputs
+other than Level 1 prices such as quoted prices for similar assets or liabilities or prices quoted in inactive markets; and Level 3, defined as unobservable inputs that are significant
+to the fair value of the asset or liability, and for which little or no market data exists, therefore requiring management to utilize its own assumptions to provide its best estimate of what market
+participants would use in valuing the asset or liability. 
+The
+liability for the estimated fair value of the contingent consideration in connection with our acquisitions of MET and BTS was initially determined using Level 3 inputs based
+on a probabilistic calculation whereby we assigned estimated probabilities to achieving the earn-out targets and then discounted the total contingent consideration to net present value. The MET and
+BTS earn-out targets were completed during Fiscal 2013 and the remaining liability at March 31, 2014 and March 31, 2013 related to deferred acquisition payments discounted to net present
+value using Level 1 inputs. The following table reconciles this liability measured at fair value on a recurring basis for Fiscal 2014 (in thousands): 
+Balance at March 31, 2013 
+$ 
+961 
+Deferred payments made to MET shareholders 
+(409 
+) 
+Earn-out payments made to BTS shareholders 
+(250 
+) 
+Change in fair value included in net income 
+25 
+Balance at March 31, 2014 
+$ 
+327 
+The
+change in the estimated fair value of this liability during the current fiscal year resulted primarily from payments to the shareholders of BTS related to the achievement of earn-out
+targets and reductions to our MET estimates regarding both the probability of achieving certain earn-out targets and the amounts of certain future deferred payments. 
+The
+current portion of the liability at March 31, 2014 and 2013 of approximately $327,000 and $652,000, respectively, is included within accrued liabilities in the accompanying
+consolidated balance sheets. The change in the estimated fair value of the liability for the years ended March 31, 2014, 2013, and 2012 is included as part of operating expenses in the
+accompanying consolidated statements of operations. 
+Other
+than the above, we did not have any material financial assets or liabilities measured at fair value on a recurring basis using Level 3 inputs as of March 31, 2014. 
+Our
+non-financial assets, such as goodwill, intangible assets and property and equipment, are measured at fair value on a non-recurring basis, generally when there is a transaction
+involving those assets such as a purchase transaction, a business combination or an adjustment for impairment. See Notes 4 and 5 above for further discussion regarding certain of our intangible
+assets and goodwill balances (including goodwill impairment) that were measured at fair value, using certain Level 3 inputs, during the fiscal years ended March 31, 2014, 2013, and 2012. 
+76 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+7. Credit Facility 
+In October 2008, we entered into a $19.5 million credit facility with California Bank & Trust ("CB&T"). This credit facility provided for a two-year revolving line of
+credit with borrowings of up to $12.0 million and a $7.5 million 48-month term note. In September 2010, we entered into a modification agreement with CB&T to extend the expiration date
+of our revolving line of credit to October 1, 2012. We repaid in full all principal and accrued interest under the term note in September 2012. The term note did not contain any early
+termination fees or prepayment penalties. 
+In
+September 2012, we entered into a second modification agreement with CB&T to extend the expiration date of our revolving line of credit to October 1, 2014. Interest on borrowed
+amounts under the revolving line of credit are payable monthly at a rate equal to the current stated prime rate (3.25% at March 31, 2014) up to the current stated prime rate plus 0.25%,
+depending on aggregate deposit balances maintained at CB&T in relation to the total loan commitment under the credit facility. We are obligated to pay an unused line fee of 0.25% per annum applied to
+the average unused portion of the revolving line of credit during the preceding month. The revolving line of credit does not contain early termination fees and is secured by substantially all of our
+assets. 
+As
+of March 31, 2014 and 2013, no amounts were outstanding under the credit facility with CB&T. Availability under this line of credit may be reduced or otherwise limited as a
+result of our obligations to comply with certain financial and other covenants. As of March 31, 2014, we were in compliance with all such covenants. 
+8. Income Taxes 
+The reconciliation of our income tax provision to taxes computed at U.S. federal statutory rates is as follows: 
+Year Ended March 31, 
+2014 
+2013 
+2012 
+(In thousands) 
+Income tax provision at statutory rates 
+$ 
+688 
+$ 
+554 
+$ 
+663 
+State income taxes net of federal benefit 
+48 
+18 
+562 
+Tax credits 
+(290 
+) 
+(39 
+) 
+(246 
+) 
+Change in fair value of contingent acquisition consideration 
+8 
+(62 
+) 
+(211 
+) 
+Compensation charges 
+22 
+31 
+59 
+Unrecognized tax benefits 
+(4 
+) 
+— 
+(276 
+) 
+Change in valuation allowance 
+185 
+188 
+— 
+Other 
+47 
+26 
+92 
+Provision for income taxes 
+$ 
+704 
+$ 
+716 
+$ 
+643 
+77 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+8. Income Taxes (Continued) 
+The
+components of deferred tax assets and liabilities are as follows: 
+March 31, 
+2014 
+2013 
+(In thousands) 
+Deferred tax assets: 
+Net operating losses 
+$ 
+5,835 
+$ 
+7,031 
+Credit carry forwards 
+1,350 
+960 
+Deferred compensation and payroll 
+958 
+913 
+Bad debt allowance and other reserves 
+516 
+462 
+Deferred rent 
+165 
+315 
+Other, net 
+198 
+156 
+Total deferred tax assets 
+9,022 
+9,837 
+Valuation allowance 
+(373 
+) 
+(188 
+) 
+Total deferred tax assets, net of valuation allowance 
+8,649 
+9,649 
+Deferred tax liabilities: 
+Property and equipment 
+(285 
+) 
+(482 
+) 
+Acquired intangibles 
+(276 
+) 
+(535 
+) 
+Goodwill 
+(547 
+) 
+(381 
+) 
+Total deferred tax liabilities 
+(1,108 
+) 
+(1,398 
+) 
+Net deferred tax assets 
+$ 
+7,541 
+$ 
+8,251 
+The
+components of current and deferred federal and state income tax provisions and (benefits) are as follows: 
+Year Ended March 31, 
+2014 
+2013 
+2012 
+(In thousands) 
+Current income tax provision (benefit): 
+Federal 
+$ 
+21 
+$ 
+(20 
+) 
+$ 
+(221 
+) 
+State 
+20 
+99 
+208 
+Deferred income tax provision: 
+Federal 
+330 
+425 
+12 
+State 
+333 
+212 
+644 
+Net income tax provision 
+$ 
+704 
+$ 
+716 
+$ 
+643 
+At
+March 31, 2014, we had approximately $838,000 in federal alternative minimum tax credit carryforwards that can be carried forward indefinitely. We had $18.6 million of
+federal net operating loss carryforwards at March 31, 2014 that begin to expire in 2021. We also had $8.0 million of state net operating loss carryforwards at March 31, 2014, of
+which, $7.8 million are scheduled to expire in 2015 and $160,000 are scheduled to expire in 2031. 
+78 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+8. Income Taxes (Continued) 
+Due
+to changes in stock ownership, our federal net operating loss carryforwards of approximately $18.6 million as of March 31, 2014 and other federal attributes are subject
+to an annual limitation under Section 382 of the Internal Revenue Code. As of March 31, 2014, based on the cumulative amount of tax attributes that have become available under the
+limitation imposed by Section 382, all of our net operating losses are now fully available for use. Our deferred tax assets at March 31, 2014 do not include approximately $958,000 of
+excess tax benefits from employee stock option exercises that are a component of our net operating loss carryforwards. If and when such excess tax benefits are realized, stockholders' equity will be
+increased. 
+As
+of March 31, 2014 and 2013, we recorded a valuation allowance against certain of our state net operating loss carryforwards which we estimated were likely to not be realized
+within the applicable carryforward period in the amount of $373,000 and $188,000, respectively, net of federal tax benefit. In making our determination as to the realizability of our deferred tax
+assets, we reviewed all available positive and negative evidence, including reversal of deferred tax liabilities, potential carrybacks, projected future taxable income, tax planning strategies and
+recent financial performance. 
+Unrecognized Tax Benefits 
+As of March 31, 2014 and 2013, our gross unrecognized tax benefits were $281,000 and $218,000, respectively, of which $217,000
+and $115,000, respectively, if recognized, would affect our effective tax rate. 
+We
+recognize interest and/or penalties related to income tax matters in income tax expense. As of March 31, 2014 and 2013, we had accrued cumulatively $53,000 and $68,000,
+respectively, for the payment of potential interest and penalties. 
+A
+reconciliation of the beginning and ending balances of the total amounts of gross unrecognized tax benefits is as follows: 
+Year Ended March 31, 
+2014 
+2013 
+2012 
+(In thousands) 
+Gross unrecognized tax benefits at beginning of year 
+$ 
+218 
+$ 
+1,692 
+$ 
+1,941 
+Increases for tax positions taken in prior years 
+106 
+— 
+97 
+Decreases for tax positions taken in prior years 
+(53 
+) 
+(1,431 
+) 
+(10 
+) 
+Increases for tax positions taken in the current year 
+41 
+17 
+20 
+Lapse in statute of limitations 
+(31 
+) 
+(60 
+) 
+(356 
+) 
+Gross unrecognized tax benefits at March 31 
+$ 
+281 
+$ 
+218 
+$ 
+1,692 
+As
+of March 31, 2012, our unrecognized tax benefits included $1.4 million related to estimated tax credit carryforwards which, if recognized, would have given rise to a
+deferred tax asset. As of March 31, 2013, we concluded that the information necessary to compute and substantiate the credits was not available or reasonably obtainable. As such, we will
+neither recognize a deferred tax asset for the estimated credit carryforwards, nor continue maintaining an offsetting amount of unrecognized tax benefits. We do not anticipate a significant change in
+gross unrecognized tax benefits within the next twelve months. 
+79 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+8. Income Taxes (Continued) 
+We
+are subject to taxation in the U.S. and various states. We are subject to U.S. federal tax examination for fiscal tax years ended March 31, 2011 or later, and state and local
+income tax examination for fiscal tax years ended March 31, 2010 or later. 
+9. Commitments and Contingencies 
+Litigation and Other Contingencies 
+As a provider of traffic engineering services, products and solutions, we are currently, and may in the future, from time to time, be
+involved in litigation relating to claims arising out of our operations in the normal course of business. While we cannot accurately predict the outcome of any such litigation, we currently are not a
+party to any legal proceedings, the adverse outcome of which, in management's opinion, individually or in the aggregate, would have a material adverse effect on our consolidated results of operations,
+financial position or cash flows. 
+Operating Leases 
+In May 2007, we entered into an agreement to lease 52,000 square feet of office space in Santa Ana, California for a term of
+88 months. In September 2007, we relocated our headquarters and principal operations into this space. The monthly lease rate was $102,000 during the first year of the lease and increases each
+year thereafter, up to a maximum of $120,000 during the last year of the lease. The lease may be extended for a period of five years, at our option, at a lease rate to be based on the market lease
+rate for comparable property determined as of the commencement date of the extension period. Additionally, the lease agreement provided for $1.8 million in incentives in the form of tenant
+improvement allowances, which we recorded as deferred rent and capitalized leasehold improvements in our consolidated balance sheet. The deferred rent amount reduces monthly rent expense over the term
+of the lease, and the capitalized leasehold improvements amount are being depreciated over the estimated useful life of the related leasehold improvements or the term of the lease, whichever is
+shorter. 
+In
+February 2014, we entered into an amendment to the lease for our principal facility, which reduced our office space by approximately 11,000 square feet and changed the lease term to
+96 months, commencing on April 1, 2014. The monthly lease rate will be approximately $76,000 during the first year of the amended term and increases each year thereafter, up to a maximum
+of approximately $90,000 during the last year of the term. Additionally, the lease amendment provides for approximately $328,000 in incentives in the form of tenant improvement allowances, which we
+recorded as deferred rent and other receivables in our consolidated balance sheet. The deferred rent amount will reduce monthly rent expense over the term of the lease amendment, and the other
+receivables will be capitalized as leasehold improvements during Fiscal 2015 and depreciated over the estimated useful life of the improvements, or the term of the lease amendment, whichever is
+shorter. 
+80 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+9. Commitments and Contingencies (Continued) 
+We
+have lease commitments for facilities in various locations throughout the U.S., as well as for certain equipment. Future minimum rental payments under these non-cancelable operating
+leases at March 31, 2014 were as follows: 
+Year Ending March 31,
+(In thousands) 
+2015 
+$ 
+1,480 
+2016 
+1,644 
+2017 
+1,565 
+2018 
+1,424 
+2019 
+1,297 
+Thereafter 
+3,230 
+$ 
+10,640 
+Rent
+expense totaled approximately $1.9 million for each of the fiscal years ended March 31, 2014, 2013 and 2012. 
+Related Party Transaction 
+We previously subleased office space to Maxxess Systems, Inc. ("Maxxess"), one of our former subsidiaries that we sold in
+September 2003. Maxxess is currently owned by an investor group that includes one current director, who is the Chief Executive Officer of Maxxess, and a former director. The sublease terminated in
+September 2007, at which time Maxxess owed us an aggregate of $274,000 related to this sublease and certain ancillary corporate services that we provided to Maxxess. In August 2009, Maxxess executed a
+promissory note payable to Iteris in the original principal amount of $274,000. The promissory note accrued interest at a rate of 6% per annum, compounded annually, with accrued interest to be paid
+annually on the first business day of each calendar year; and allowed payments under the note to be made in bona fide services rendered by Maxxess to Iteris, to the extent such services and amounts
+were pre-approved in writing by us. All amounts outstanding under the note was to become due and payable on the earliest of (i) August 10, 2014, (ii) a change of control in
+Maxxess, or (iii) a financing by Maxxess resulting in gross proceeds of at least $10 million. 
+On
+July 23, 2013, the promissory note from Maxxess was amended and restated. The amended and restated note bears interest at a rate of 6% per annum, compounded annually, with
+accrued interest to be paid quarterly on the first business day of each calendar quarter. Payments under the amended and restated note may only be paid in cash and all amounts outstanding will become
+due and payable on the earliest of (i) August 10, 2016, (ii) a change of control in Maxxess, or (iii) a financing by Maxxess resulting in gross proceeds of at least
+$10 million. As of March 31, 2014, approximately $259,000 of the original principal balance was outstanding and payable to Iteris. We have previously fully reserved for amounts owed to
+us by Maxxess and all outstanding principal remains fully reserved. 
+81 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+9. Commitments and Contingencies (Continued) 
+Inventory Purchase Commitments 
+At March 31, 2014, we had firm commitments to purchase approximately $2.9 million of inventory, operating assets and
+other supplies, which are expected to occur primarily during the first and second quarters of our fiscal year ending March 31, 2015. 
+10. Stockholders' Equity 
+Preferred Stock 
+Our certificate of incorporation provides for the issuance of up to 2,000,000 shares of preferred stock. Our Board of Directors is
+authorized to issue from time to time such authorized but unissued shares of preferred stock in one or more series and to fix or alter the designations, preferences, rights and any qualifications,
+limitations or restrictions of the shares of each such series, including the dividend, conversion, voting, redemption and liquidation rights. As of March 31, 2014 and 2013, there were no
+outstanding shares of preferred stock, and we do not currently have plans to issue any shares of preferred stock. 
+In
+August 2009, our Board of Directors adopted a stockholder rights plan, which calls for preferred stock purchase rights (each, a "Right") to be distributed, as a dividend, at the rate
+of one Right for each share of common stock held as of September 3, 2009. Each Right will entitle holders of common stock to buy one one-thousandth of one share of Series A Junior
+Participating Preferred Stock of Iteris. A further description and terms of the Rights are set forth in the Rights Agreement dated August 20, 2009 by and between Iteris and Computershare Trust
+Company, N.A., as rights agent. In connection with the stockholder rights plan, our Board of Directors approved the adoption of a Certificate of Designations, which created the Series A Junior
+Participating Preferred Stock, and likewise authorized the filing of a Certification of Elimination to eliminate the two series of junior participating preferred stock, which were originally created
+in April 1998 in connection with our previous stockholder rights plan which expired in 2008 
+Common Stock Warrants 
+As of March 31, 2014, we had no outstanding warrants to purchase shares of our common stock. All warrants have been exercised,
+forfeited or cancelled. 
+Common Stock Reserved for Future Issuance 
+The following summarizes common stock reserved for future issuance at March 31, 2014: 
+Number of Shares 
+(In thousands) 
+Stock options outstanding 
+2,019 
+Restricted stock units outstanding 
+195 
+Authorized for future issuance under stock incentive plans 
+263 
+2,477 
+82 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+11. Employee Benefit Plans 
+Stock Incentive Plans 
+In September 2007, our stockholders approved the 2007 Omnibus Incentive Plan (the "2007 Plan"), which provides that options to purchase
+shares of our unissued common stock may be granted to our employees, officers, consultants and directors at exercise prices which are equal to or greater than the market value of our common stock on
+the date of grant. Options expire no more than ten years after the date of grant and generally vest at the rate of 25% on each of the first four anniversaries of the grant date. The 2007 Plan also
+allows for the issuance of stock appreciation rights, restricted stock, restricted stock units ("RSUs") and other stock-based awards based on the value of our common stock. New shares are issued to
+satisfy stock option exercises and share issuances under the 2007 Plan. In September 2009, our stockholders approved an amendment to increase the number of shares of our common stock authorized and
+reserved for issuance under the 2007 Plan by 800,000 shares to a total of 1,650,000 shares. In September 2012, our stockholders approved an amendment to increase the number of shares of our common
+stock authorized and reserved for issuance under the 2007 Plan by 800,000 shares to a total of 2,450,000 shares. At March 31, 2014, there were approximately 263,000 shares of common stock
+available for grant under this plan. As of March 31, 2014, options to purchase approximately 1,757,000 shares of common stock, as well as 195,000 RSUs, were outstanding under the 2007 Plan. 
+Our
+1997 Stock Incentive Plan (the "1997 Plan") terminated in September 2007; however, all stock options outstanding under the 1997 Plan remain outstanding pursuant to the terms of such
+stock options. As of March 31, 2014, options to purchase approximately 262,000 shares of our common stock were outstanding under the 1997 Plan. No further options or other stock-based awards
+may be granted under the 1997 Plan. 
+Certain
+options granted under the 2007 Plan and the 1997 Plan (collectively, the "Plans") and the RSUs granted under the 2007 Plan provide for accelerated vesting of unvested options in
+the event of a change in control under certain circumstances. 
+83 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+11. Employee Benefit Plans (Continued) 
+Stock Options 
+A summary of activity in the Plans with respect to our stock options for Fiscal 2014 is as follows: 
+Options 
+Weighted 
+Average 
+Exercise 
+Price Per 
+Share 
+Weighted 
+Average 
+Remaining 
+Contractual 
+Life 
+Aggregate 
+Intrinsic Value 
+(In thousands) 
+(Years) 
+(In thousands) 
+Options outstanding at March 31, 2013 
+1,744 
+$ 
+1.74 
+Granted 
+710 
+1.85 
+Exercised 
+(284 
+) 
+0.88 
+Forfeited 
+(54 
+) 
+1.50 
+Expired 
+(98 
+) 
+2.43 
+Options outstanding at March 31, 2014 
+2,018 
+$ 
+1.88 
+6.6 
+$ 
+548 
+Options exercisable at March 31, 2014 
+1,125 
+$ 
+1.98 
+4.6 
+$ 
+316 
+Vested and expected to vest at March 31, 2014 
+1,875 
+$ 
+1.88 
+6.4 
+$ 
+518 
+Options exercisable at March 31, 2014 pursuant to a change-in-control 
+2,018 
+$ 
+1.88 
+6.6 
+$ 
+548 
+Restricted Stock Units 
+In August 2010, we began granting RSUs under the 2007 Plan to certain of our employees. RSU awards are stock-based awards that entitle
+the holder to receive one share of our common stock for each RSU upon vesting. RSUs vest at the rate of 25% on each of the first four anniversaries of the grant date provided that the holder remains
+in service (as defined by the 2007 Plan) as of the vesting date. The fair value per RSU is determined based on the closing market price of our common stock on the grant date. 
+84 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+11. Employee Benefit Plans (Continued) 
+A summary of activity with respect to our RSUs for Fiscal 2014 is as follows: 
+# of Shares 
+Weighted 
+Average 
+Price Per 
+Share 
+Weighted 
+Average 
+Remaining 
+Life 
+Aggregate 
+Intrinsic Value 
+(In thousands) 
+(Years) 
+(In thousands) 
+RSUs outstanding at March 31, 2013 
+210 
+$ 
+1.39 
+Granted 
+90 
+1.81 
+Vested 
+(76 
+) 
+1.40 
+Forfeited 
+(29 
+) 
+1.09 
+RSUs outstanding at March 31, 2014 
+195 
+$ 
+1.58 
+2.3 
+$ 
+82 
+Expected to vest at March 31, 2014 
+169 
+$ 
+1.57 
+2.2 
+$ 
+73 
+Common stock issuable (for RSUs) at March 31, 2014 upon a change-in-control 
+195 
+$ 
+1.58 
+2.3 
+$ 
+82 
+Stock-Based Compensation 
+The following table presents stock-based compensation expense that is included in each functional line item in our consolidated
+statements of operations: 
+Year Ended March 31, 
+2014 
+2013 
+2012 
+(In thousands) 
+Cost of revenues 
+$ 
+30 
+$ 
+42 
+$ 
+45 
+Selling, general and administrative expense 
+246 
+237 
+280 
+Research and development expense 
+24 
+— 
+6 
+Total stock-based compensation 
+$ 
+300 
+$ 
+279 
+$ 
+331 
+At
+March 31, 2014, there was approximately $840,000 of unrecognized compensation expense related to unvested stock options and RSUs. This expense is currently expected to be
+recognized over a weighted average period of approximately 2.7 years. If there are any modifications or cancellations of the underlying unvested awards, we may be required to accelerate,
+increase or cancel any remaining unearned stock-based compensation expense. Future stock-based compensation expense and unearned stock-based compensation will increase to the extent that we grant
+additional stock options, RSUs or other stock-based awards. 
+85 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+11. Employee Benefit Plans (Continued) 
+The
+grant date fair value of stock options granted was estimated using the following weighted-average assumptions: 
+Year Ended March 31, 
+2014 
+2013 
+2012 
+Expected life—years 
+7.0 
+7.0 
+7.0 
+Risk-free interest rate 
+2.0 
+% 
+1.2 
+% 
+1.6 
+% 
+Expected volatility of common stock 
+51 
+% 
+52 
+% 
+52 
+% 
+Dividend yield 
+— 
+% 
+— 
+% 
+— 
+% 
+A
+summary of certain fair value and intrinsic value information pertaining to our stock options is as follows: 
+Year Ended March 31, 
+2014 
+2013 
+2012 
+(In thousands, except per 
+share amounts) 
+Weighted average grant date fair value per share of options granted 
+$ 
+0.99 
+$ 
+0.81 
+$ 
+0.61 
+Intrinsic value of options exercised 
+$ 
+281 
+$ 
+42 
+$ 
+7 
+Employee Incentive Programs 
+Under the terms of a Profit Sharing Plan, we may contribute to a trust fund such amounts as determined annually by the Board of
+Directors. No contributions were made during the fiscal years ended March 31, 2014, 2013 and 2012. 
+We
+sponsor a defined contribution 401(k) plan (the "401(k) Plan"), adopted in 1990, under which eligible associates voluntarily contribute to the plan, up to IRS maximums, through
+payroll deductions. We match up to 50% of contributions, up to a stated limit, with all matching contributions being fully vested after three years of service. Our matching contributions under the
+401(k) Plan were approximately $504,000, $498,000 and $475,000 for the fiscal years ended March 31, 2014, 2013 and 2012, respectively. 
+12. Stock Repurchase Program 
+In August 2011, our Board of Directors approved a stock repurchase program pursuant to which we were authorized to acquire up to $3 million of our outstanding common stock from
+time to time through August 2012. We acquired approximately 964,000 shares under this original program. On August 9, 2012, our Board of Directors approved a new stock repurchase program
+pursuant to which we may acquire up to $3 million of our outstanding common stock for an unspecified length of time. Under the new program, we may repurchase shares from time to time in
+open-market and privately negotiated transactions and block trades, and may also repurchase shares pursuant to a 10b5-1 trading plan during our closed trading windows. There is no guarantee as to the
+exact number of shares that will be repurchased. We may modify or terminate the repurchase program at any time without prior notice. 
+86 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+12. Stock Repurchase Program (Continued) 
+For
+our fiscal year ended March 31, 2014, 2013, and 2012, we repurchased approximately 196,000, 1,524,000, and 574,000 shares of our common stock, respectively. From inception of
+the program in August 2011 through March 31, 2014, we repurchased approximately 2,293,000 shares of our common stock for an aggregate price of approximately $3.6 million, at an average
+price per share of $1.54. As of March 31, 2014, all repurchased shares have been retired and resumed their status as authorized and unissued shares of our common stock. As of March 31,
+2014, approximately $747,000 remains available for the repurchase of our common stock under our current program. 
+13. Business Segments, Significant Customer and Geographic Information 
+Business Segments 
+We operate in three reportable segments: Roadway Sensors, Transportation Systems and iPerform. 
+The
+Roadway Sensors segment includes, among other products, our Vantage, VantageNext, VersiCam, Vantage Vector, SmartCycle, SmartSpan, P10, P100 and Abacus vehicle detection systems for
+traffic intersection control, incident detection and certain highway traffic data collection applications. 
+The
+Transportation Systems segment includes transportation engineering and consulting services, and the development of transportation management and traveler information systems for the
+ITS industry. During Fiscal 2012 and Fiscal 2013, this segment included the operations of MET, which specializes in 511/ advanced traveler information systems and offers predictive weather and
+ClearPath Weather management tools that allow users to create solutions to meet roadway maintenance decision needs. As of April 1, 2013, the predictive weather and ClearPath services were
+reassigned to the iPerform segment to better align our predictive weather and traffic capabilities, resources and initiatives. Prior year segment information presented in the table below has been
+re-classified to reflect this change. 
+The
+iPerform segment includes our performance measurement and information management solutions, including all the operations of BTS, which specializes in transportation performance
+measurement, as well as the predictive weather and ClearPath Weather services reassigned from the Transportation Systems segment on April 1, 2013. During Fiscal 2012, we began the development
+of iPeMS. iPeMS is a state-of-the-art, information management software suite that utilizes a wide range of data resources and
+analytical techniques to determine current and future traffic patterns, permitting the effective performance analysis and management of traffic infrastructure resources. This information can then be
+analyzed by traffic professionals to measure how a transportation network is performing and to identify potential areas of improvement. iPeMS is also capable of providing users with predictive traffic
+analytics and easy-to-use visualization and animation features based on historical traffic conditions. 
+The
+accounting policies of our reportable segments are the same as those described in the summary of significant accounting policies (Note 1). Certain corporate expenses,
+including interest and amortization of intangible assets, are not allocated to the segments. The reportable segments are each managed separately because they manufacture and distribute distinct
+products or provide services with different processes. All reported segment revenues are derived from external customers. 
+87 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+13. Business Segments, Significant Customer and Geographic Information (Continued) 
+Selected
+financial information for our reportable segments for the fiscal years ended March 31, 2014, 2013 and 2012 is as follows: 
+Roadway 
+Sensors 
+Transportation 
+Systems 
+iPerform 
+Total 
+(In thousands) 
+Year Ended March 31, 2014 
+Revenues 
+$ 
+31,769 
+$ 
+30,524 
+$ 
+5,935 
+$ 
+68,228 
+Depreciation 
+208 
+161 
+118 
+487 
+Segment income (loss) 
+5,791 
+3,363 
+(1,575 
+) 
+7,579 
+Year Ended March 31, 2013 
+Revenues 
+$ 
+26,002 
+$ 
+30,010 
+$ 
+5,673 
+$ 
+61,685 
+Depreciation 
+221 
+362 
+20 
+603 
+Segment income (loss) 
+4,119 
+3,561 
+(233 
+) 
+7,447 
+Year Ended March 31, 2012 
+Revenues 
+$ 
+27,679 
+$ 
+29,792 
+$ 
+935 
+$ 
+58,406 
+Depreciation 
+194 
+393 
+5 
+592 
+Segment income (loss) 
+4,813 
+3,151 
+(367 
+) 
+7,597 
+The
+following table reconciles total segment income to consolidated income from continuing operations before income taxes: 
+Year Ended March 31, 
+2014 
+2013 
+2012 
+(in thousands) 
+Segment income: 
+Total income from reportable segments 
+$ 
+7,579 
+$ 
+7,447 
+$ 
+7,597 
+Unallocated amounts: 
+Corporate and other expenses 
+(4,903 
+) 
+(5,350 
+) 
+(5,695 
+) 
+Amortization of intangible assets 
+(627 
+) 
+(644 
+) 
+(504 
+) 
+Change in fair value of contingent acquisition consideration 
+(25 
+) 
+181 
+619 
+Other income, net 
+— 
+2 
+4 
+Interest expense, net 
+— 
+(6 
+) 
+(72 
+) 
+Income from continuing operations before income taxes 
+$ 
+2,024 
+$ 
+1,630 
+$ 
+1,949 
+Significant Customer and Geographic Information 
+We currently have, and historically have had, a diverse customer base. For Fiscal 2014, one individual customer represented
+approximately 11% of our total revenues and no other individual customer represented greater than 10% of our total revenues. For Fiscal 2013, one individual customer represented approximately 13% of
+our total revenues and no other individual customer represented greater than 10% of our total revenues. For Fiscal 2012, no individual customer represented greater than 10% of our total revenues. 
+88 
+Table of Contents 
+Iteris, Inc. 
+Notes to Consolidated Financial Statements (Continued) 
+March 31, 2014 
+13. Business Segments, Significant Customer and Geographic Information (Continued) 
+No
+individual customer or government agency had a receivable balance at March 31, 2014 or 2013 greater than 10% of our total trade accounts receivable balances as of
+March 31, 2014 and 2013, respectively. 
+The
+following table sets forth the percentages of our revenues, by geographic region, derived from shipments to, or contract, service and other revenues from, external customers located
+outside the U.S.: 
+Year Ended March 31, 
+2014 
+2013 
+2012 
+Middle East 
+4 
+% 
+3 
+% 
+— 
+% 
+Asia 
+— 
+— 
+1 
+Other 
+1 
+1 
+1 
+5 
+% 
+4 
+% 
+2 
+% 
+Substantially
+all of our long-lived assets are held in the U.S. 
+14. Quarterly Financial Data (Unaudited) 
+Quarter Ended:
+Revenues 
+Gross 
+Profit 
+Net Income 
+Basic 
+Net Income 
+per Share 
+Diluted 
+Net Income 
+per Share 
+(In thousands, except per share amounts) 
+June 30, 2013 
+$ 
+17,030 
+$ 
+6,726 
+$ 
+460 
+$ 
+0.01 
+$ 
+0.01 
+September 30, 2013 
+17,027 
+6,912 
+661 
+0.02 
+0.02 
+December 31, 2013 
+16,548 
+6,192 
+238 
+0.01 
+0.01 
+March 31, 2014 
+17,623 
+6,144 
+50 
+0.00 
+0.00 
+$ 
+68,228 
+$ 
+25,974 
+$ 
+1,409 
+$ 
+0.04 
+* 
+$ 
+0.04 
+* 
+June 30, 2012 
+$ 
+16,304 
+$ 
+6,264 
+$ 
+676 
+$ 
+0.02 
+$ 
+0.02 
+September 30, 2012 
+15,504 
+6,071 
+550 
+0.02 
+0.02 
+December 31, 2012 
+13,994 
+5,151 
+1,097 
+0.03 
+0.03 
+March 31, 2013 
+15,883 
+5,772 
+56 
+0.00 
+0.00 
+$ 
+61,685 
+$ 
+23,258 
+$ 
+2,379 
+$ 
+0.07 
+* 
+$ 
+0.07 
+* 
+* Annual
+per share amounts may not agree to the sum of the quarterly per share amounts due to differences between average shares outstanding during the periods. 
+89 
+Table of Contents 
+Exhibit Index 
+Exhibit 
+Number 
+Description 
+Reference 
+2.1 
++ 
+Stock Purchase Agreement dated December 23, 2010 by and among Iteris, Inc., Meridian Environmental Technology, Inc., ("MET") the shareholders of MET and Kathy J. Osborne as the Shareholders
+Representative 
+Exhibit 2.1 to the registrant's Quarterly Report on Form 10-Q for the quarter ended December 31, 2010 as filed with the SEC on February 14, 2011 
+2.2 
++ 
+Asset Purchase Agreement by and between Iteris, Inc. and Bendix Commercial Vehicle Systems LLC, dated as of July 25, 2011 
+Exhibit 2.1 to the registrant's Current Report on Form 8-K/A as filed with the SEC on November 1, 2011 
+3.1 
+Restated Certificate of Incorporation of the registrant 
+Exhibit 3.1 to the registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009 as filed with the SEC on October 30, 2009 
+3.2 
+Certificate of Designations of Series A Junior Participating Preferred Stock 
+Exhibit 3.2 to the registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009 as filed with the SEC on October 30, 2009 
+3.3 
+Bylaws of the registrant, as amended 
+Exhibit 4.2 to the registrant's Registration Statement on Form S-1 (Reg. No. 033-67932) as filed with the SEC on July 6, 1993 
+3.4 
+Certificates of Amendment to Bylaws of the registrant dated April 24, 1998 and August 10, 2001 
+Exhibit 3.4 to the registrant's Annual Report on Form 10-K/A for the year ended March 31, 2003 as filed with the SEC on July 29, 2003 
+3.5 
+Certificate of Amendment to Bylaws of registrant dated September 9, 2004 
+Exhibit 3.1 to the registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2004 as filed with the SEC on November 15, 2004 
+3.6 
+Certificate of Amendment to Bylaws of registrant effective September 16, 2005 
+Exhibit 3.5 to the registrant's Annual Report on Form 10-K for the year ended March 31, 2007 
+3.7 
+Certificate of Amendment to Bylaws of registrant effective December 7, 2007 
+Exhibit 3.1 to the registrant's Current Report on Form 8-K as filed with the SEC on December 13, 2007 
+3.8 
+Certificate of Amendment to Bylaws of registrant, effective August 20, 2009 
+Exhibit 3.3 to the registrant's Current Report on Form 8-K as filed with the SEC on August 21, 2009 
+4.1 
+Specimen of common stock certificate 
+Exhibit 4.1 to registrant's Registration Statement on Form 8-A as filed with the SEC on December 8, 2004 
+90 
+Table of Contents 
+Exhibit 
+Number 
+Description 
+Reference 
+4.2 
+Rights Agreement dated August 20, 2009 between the registrant and Computershare Trust Company, N.A., which includes the form of Certificate of Designations for the Series A Junior Participating Preferred Stock,
+the form of Right Certificate, and Summary of Rights to Purchase Preferred Stock as exhibits thereto 
+Exhibit 4.1 to the registrant's Current Report on Form 8-K as filed with the SEC on August 21, 2009 
+4.3 
+Amendment No. 1 To Rights Agreement, entered into as of August 8, 2012 by and between Iteris, Inc. and Computershare Trust Company, N.A. 
+Exhibit 4.1 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 as filed with the SEC on August 10, 2012 
+10.1 
+Form of Indemnity Agreement entered into by the registrant and certain of its officers and directors 
+Exhibit 19.4 to the registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 1988 
+10.2 
+Form of Indemnification Agreement entered into by the registrant and certain of its officers and directors 
+Exhibit 10.5 to the registrant's Annual Report on Form 10-K for the year ended March 31, 2004 as filed with the SEC on June 29, 2004 
+10.3 
+* 
+1997 Stock Incentive Plan (the "1997 Plan") as amended on May 3, 2003, as further amended on December 15, 2004 
+Exhibit 10.32 to the registrant's Annual Report on Form 10-K for the year ended March 31, 2005 as filed with the SEC on July 14, 2005 
+10.4 
+* 
+Form of Notice of Grant of Stock Option for 1997 Plan 
+Exhibit 99.2 to the registrant's Registration Statement on Form S-8 (File No. 333-30396) as filed with the SEC on February 14, 2000 
+10.5 
+* 
+Form of Stock Option Agreement for the 1997 Plan 
+Exhibit 99.3 to the registrant's Registration Statement on Form S-8 (File No. 333-30396) as filed with the SEC on February 14, 2000 
+10.6 
+* 
+Form of Addendum to Stock Option Agreement for 1997 Plan—Involuntary Termination Following Corporate Transaction or Change in Control 
+Exhibit 99.4 to the registrant's Registration Statement on Form S-8 (File No. 333-30396) as filed with the SEC on February 14, 2000 
+10.7 
+* 
+Form of Addendum to Stock Option Agreement for 1997 Plan—Limited Stock Appreciation Rights 
+Exhibit 99.5 to the registrant's Registration Statement on Form S-8 (File No. 333-30396) as filed with the SEC on February 14, 2000 
+10.8 
+* 
+Form of Stock Issuance Agreement for 1997 Plan 
+Exhibit 99.6 to the registrant's Registration Statement on Form S-8 (File No. 333-30396) as filed with the SEC on February 14, 2000 
+10.9 
+* 
+Form of Addendum to Stock Issuance Agreement for 1997 Plan—Involuntary Termination Following Corporate Transaction/Change in Control 
+Exhibit 99.7 to the registrant's Registration Statement on Form S-8 (File No. 333-30396) as filed with the SEC on February 14, 2000 
+91 
+Table of Contents 
+Exhibit 
+Number 
+Description 
+Reference 
+10.10 
+* 
+Form of Notice of Grant of Automatic Stock Option for 1997 Plan—Initial Grant 
+Exhibit 99.8 to Exhibit 99.8 to registrant's Registration Statement on Form S-8 (File No. 333-30396) as filed with the SEC on February 14, 2000 
+10.11 
+* 
+Form of Notice of Grant of Automatic Stock Option for 1997 Plan—Annual Grant 
+Exhibit 99.9 to the registrant's Registration Statement on Form S-8 (File No. 333-30396) as filed with the SEC on February 14, 2000 
+10.12 
+* 
+Form of Automatic Stock Option Agreement for 1997 Plan 
+Exhibit 99.10 to the registrant's Registration Statement on Form S-8 (File No. 333-30396) as filed with the SEC on February 19, 2000 
+10.13 
+* 
+Iteris Inc. 1998 Stock Incentive Plan (as amended on February 7, 2000) ("1998 Plan") 
+Exhibit 10.24 to the registrant's Annual Report on Form 10-K for the year ended March 31, 2005 as filed with the SEC on July 14, 2005 
+10.14 
+* 
+Form of Notice of Grant for 1998 Plan, including forms of Option Agreement and Stock Purchase Agreement for Abbas Mohaddes 
+Exhibit 99.2 to the registrant's Registration Statement on Form S-8 (File No. 333-126834) as filed with the SEC on July 22, 2005 
+10.15 
+* 
+Form of Addendum to Stock Option Agreement for 1998 Plan 
+Exhibit 99.3 to the registrant's Registration Statement on Form S-8 (File No. 333-126834) as filed with the SEC on July 22, 2005 
+10.16 
+* 
+Form of 1997 Stock Option Agreements 
+Exhibit 99.4 to the registrant's Registration Statement on Form S-8 (File No. 333-126834) as filed with the SEC on July 22, 2005 
+10.17 
+Sublease, dated September 30, 2003, by and between Odetics, Inc. and Maij, Inc. 
+Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 as filed with the SEC on August 14, 2007 
+10.18 
+Office Lease, dated May 24, 2007, by and between Crown Carnegie Associates, LLC and Iteris, Inc. 
+Exhibit 10.2 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 as filed with the SEC on August 14, 2007 
+10.19 
+* 
+2007 Omnibus Incentive Plan 
+Exhibit 10.19 to the registrant's Annual Report on Form 10-K for the year ended March 31, 2012 as filed with the SEC on June 11, 2012 
+10.20 
+* 
+Forms of Stock Option Agreements under the 2007 Omnibus Incentive Plan 
+Exhibit 10.20 to the registrant's Annual Report on Form 10-K for the year ended March 31, 2012 as filed with the SEC on June 11, 2012 
+92 
+Table of Contents 
+Exhibit 
+Number 
+Description 
+Reference 
+10.21 
+Amended and Restated Loan and Security Agreement dated February 4, 2009 by and between California Bank & Trust and the registrant 
+Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q for the quarter ended December 31, 2008 as filed with the SEC on February 13, 2009 
+10.22 
+* 
+Form of Restricted Stock Unit Award Agreement under the 2007 Omnibus Incentive Plan 
+Exhibit 10.3 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 as filed with the SEC on July 28, 2010 
+10.23 
+Modification Agreement dated September 30, 2010 by and between Iteris, Inc. and California Bank & Trust 
+Exhibit 10.1 to the registrant's Current Report on Form 8-K as filed with the SEC on October 6, 2010 
+10.24 
+Modification Agreement dated September 28, 2012 by and between Iteris, Inc. and California Bank & Trust 
+Exhibit 10.1 to the registrant's Current Report on Form 8-K as filed with the SEC on October 3, 2012 
+10.25 
+Amended and Restated Promissory Note, effective July 23, 2013, by and between Maxxess Systems, Inc. in favor of Iteris, Inc. 
+Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2013 
+10.26 
+* 
+Employment Agreement, dated July 29, 2013, by and between Iteris, Inc. and Abbas Mohaddes 
+Exhibit 10.2 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2013 
+10.27 
+* 
+Offer Letter dated November 26, 2013 by and between Iteris, Inc. and Walter J. McBride 
+Exhibit 10.1 to the registrant's Current Report on Form 8-K filed with the SEC on December 4, 2013 
+10.28 
+* 
+Change in Control Agreement dated December 3, 2013 by and between Iteris, Inc. and Walter J. McBride 
+Exhibit 10.2 to the registrant's Current Report on Form 8-K filed with the SEC on December 4, 2013 
+10.29 
+First Amendment to Lease, dated February 21, 2014, by and between RREF II Freeway Acquisitions, LLC and Iteris, Inc. 
+Filed herewith 
+21 
+Subsidiaries of the registrant 
+Filed herewith 
+23 
+Consent of Independent Registered Public Accounting Firm, dated September 3, 2014 
+Filed herewith 
+24 
+Power of Attorney 
+Filed herewith (included on the Signature page) 
+31.1 
+Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 
+Filed herewith 
+31.2 
+Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 
+Filed herewith 
+93 
+Table of Contents 
+Exhibit 
+Number 
+Description 
+Reference 
+32.1 
+Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 
+Filed herewith 
+32.2 
+Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 
+Filed herewith 
+101.INS 
+# 
+XBRL Instance Document 
+Filed herewith 
+101.SCH 
+# 
+XBRL Taxonomy Extension Schema Document 
+Filed herewith 
+101.CAL 
+# 
+XBRL Taxonomy Extension Calculation Linkbase Document 
+Filed herewith 
+101.LAB 
+# 
+XBRL Taxonomy Extension Label Linkbase Document 
+Filed herewith 
+101.PRE 
+# 
+XBRL Taxonomy Extension Presentation Linkbase Document 
+Filed herewith 
+101.DEF 
+# 
+XBRL Taxonomy Definition Presentation Linkbase Document 
+Filed herewith 
+* Indicates
+a management contract or compensatory plan or arrangement
++ Confidential
+treatment has been requested for certain confidential portions of this exhibit pursuant to Rule 24b-2 of the Securities Exchange Act of
+1934, as amended. In accordance with Rule 24b-2, these confidential portions have been omitted from the exhibit and filed separately with the SEC.
+# Pursuant
+to Rule 406T of Regulation S-T, these interactive data files i) are not deemed filed or part of a registration statement or
+prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, are not deemed filed for purposes of Section 18 of the Securities Exchange Act of 1934, irrespective of any
+general incorporation language included in any such filings, and otherwise are not subject to liability under these sections; and ii) are deemed to have complied with Rule 405 of
+Regulation S-T ("Rule 405") and are not subject to liability under the anti-fraud provisions of the Section 17(a)(1) of the Securities Act of 1933, Section 10(b) of the
+Securities Exchange Act of 1934 or under any other liability provision if we have made a good faith attempt to comply with Rule 405 and, after we become aware that the interactive data files
+fail to comply with Rule 405, we promptly amend the interactive data files. 
+94
\ No newline at end of file
diff --git a/raw/filings/0000350868/2013/0001047469-14-007351/filing_metadata.csv b/raw/filings/0000350868/2013/0001047469-14-007351/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..9ce3287249f98c04987c738bc03dd450054cf35b
--- /dev/null
+++ b/raw/filings/0000350868/2013/0001047469-14-007351/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000350868,ITI,"ITERIS, INC.",10-K,2014-09-04,2014-03-31,2014-09-03T22:18:39.000Z,0001047469-14-007351,a2221256z10-k.htm,10-K,11369516,1,0,https://www.sec.gov/Archives/edgar/data/350868/000104746914007351/a2221256z10-k.htm,https://www.sec.gov/Archives/edgar/data/350868/000104746914007351/,2013,2013,1
diff --git a/raw/filings/0000350868/2013/0001047469-14-007351/item1.txt b/raw/filings/0000350868/2013/0001047469-14-007351/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..bd767a8b62ca765d27eaa7e6f65af3ab89958aab
--- /dev/null
+++ b/raw/filings/0000350868/2013/0001047469-14-007351/item1.txt
@@ -0,0 +1,220 @@
+ITEM 1. BUSINESS 
+Overview 
+We are a leading provider of intelligent information solutions for the traffic management market. We are focused on the development and
+application of advanced technologies and software-based information systems that reduce traffic congestion, provide measurement, management and predictive traffic analytics and improve the safety of
+surface transportation systems infrastructure. We also believe our products, services and solutions, in conjunction with sound traffic management, minimize the environmental impact of traffic
+congestion. By combining our unique intellectual property, products, decades of experience in traffic management, hyper-local weather solutions and information technologies, we offer a broad range of
+Intelligent Transportation Systems ("ITS") solutions to customers throughout the U.S. and internationally. 
+We
+were originally incorporated in Delaware in 1987. Our principal executive offices are located at 1700 Carnegie Avenue, Santa Ana, California 92705, and our telephone number at that
+location is (949) 270-9400. Our Internet website address is www.iteris.com. The inclusion of our website address in this report does not include or incorporate by reference into this
+report any information on, or accessible through, our website. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, together with
+amendments to these reports, are available on the "Investors" section of our website, free of charge, as soon as reasonably practicable after such material is electronically filed with, or furnished
+to, the Securities and Exchange Commission ("SEC"). 
+Products and Services 
+We currently operate in three reportable segments: Roadway Sensors, Transportation Systems and iPerform. The Roadway Sensors segment
+includes, among other products, our Vantage, VantageNext, VersiCam, Vantage Vector, SmartCycle, SmartSpan, P10, P100 and Abacus vehicle detection systems for traffic intersection control, incident
+detection and certain highway traffic data collection applications. 
+2 
+Table of Contents 
+The
+Transportation Systems segment includes transportation engineering and consulting services, and the development of transportation management and traveler information systems for the ITS industry.
+The iPerform segment includes our transportation performance measurement and information management solutions. The iPerform performance measurement solutions leverage its real-time data collection,
+diagnostic, fusion and warehousing platform to aggregate and compute performance measurements. This segment also offers our weather related ClearPath Weather management tools that allow users to
+create solutions to meet roadway maintenance decision needs. See Note 13 of Notes to Consolidated Financial Statements, included in Part IV, Item 15 of this report, for further
+details on our reportable segments. 
+Roadway Sensors 
+Our Roadway Sensors segment product line uses advanced image processing technology to capture and analyze video images through
+sophisticated algorithms, enabling vehicle detection and transmission of both video images and data using various communication technologies. 
+• Our Vantage and VantageNext video detection systems detect vehicle presence at intersections, as well as vehicle count,
+speed and other traffic data used in traffic management systems. Vantage video detection systems typically include up to four of our RZ-4 advanced cameras or our RZ-4 advanced wide dynamic range
+cameras and an EdgeConnect processor. Our Vantage systems give traffic managers the ability to mitigate roadway congestion by modifying traffic signal timing or detecting incidents quickly. Our
+VantageView software supplements our Vantage video detection systems by providing an integrated platform to manage and "see" video detection assets remotely over a network connection. 
+• Our Vantage Vector product is an all-in-one vehicle detection sensor with a wide range of capabilities, including stop
+bar detection, advanced-zone detection and sensing, which enable advanced safety and adaptive control applications. It includes all the proven benefits of Iteris video detection, including high
+accuracy, high availability remote viewing of video images, no trenching or pavement cutting for installation, bicycle detection capability and high precision for dilemma zone detection, by
+integrating the video field-of-view with radar sensing. Enhanced information includes the number of vehicles, speed and distance in user configurable zones that can be used for special applications. 
+• Our SmartSpan product uses proprietary dynamic zone stabilization algorithms and provides accurate and cost effective
+advance detection and stop-bar detection of vehicles at intersections equipped with span wire mounted signal lights. SmartSpan can be mounted on the same span wires holding the traffic signal without
+sacrificing detection accuracy. 
+• Our Vantage systems equipped with SmartCycle can effectively differentiate between bicycles and other vehicles with a
+single video detection camera, enabling more efficient signalized intersections and maximized traffic throughput. Agencies using bicycle timing can now benefit from bicycle-specific virtual detection
+zones that can be placed anywhere within the approaching traffic lanes, eliminating the need for separate bicycle-only detection systems. 
+• VersiCam, our integrated camera and processor video detection system, is a cost-efficient video detection system for
+smaller intersections that require only a few detection points. 
+• P10 and P100 (formerly, Pico), our compact video detection system, was developed primarily to address international video
+detection needs, and was designed for easy installation and configuration. 
+• Our Abacus products take advantage of the large number of existing installed closed-circuit television video feeds
+designed to monitor roadways, signalized intersections, tunnels and bridges 
+3 
+Table of Contents 
+to
+allow for data collection and incident detection without the set-up and calibration generally required with other systems. 
+We
+believe that future growth domestically and internationally, particularly in developing countries, will be dependent in part on the continued adoption of above-ground video detection
+technologies, instead of traditional in-pavement loop technology, to manage traffic. 
+We
+have historically experienced seasonality, particularly with respect to our Roadway Sensors revenues in our third and fourth fiscal quarters due to reductions in road construction and
+repairs during the winter months related to inclement weather conditions. 
+Transportation Systems 
+Our Transportation Systems segment includes transportation engineering and consulting services focused on the planning, design,
+development and implementation of software-based systems that integrate sensors, video surveillance, computers and advanced communications equipment to enable public agencies to monitor, control and
+direct traffic flow, assist in the quick dispatch of emergency crews and distribute real-time information about traffic conditions. Our services include planning, design and implementation of surface
+transportation infrastructure systems. We perform analysis and study goods movement, study commercial vehicle operations, provide travel demand forecasting and systems engineering, and identify
+mitigation measures to reduce traffic congestion. 
+Our
+Transportation Systems segment is largely dependent upon governmental funding and is affected by state and local budgetary issues. The current federal highway bill, which provides
+federal funding for highway, transit, safety and related transportation programs, will expire at the end of September 2014. The President signed a federal highway funding bill to keep the current
+federal highway bill operational until May of 2015. We expect the extension to encourage government agencies to include ITS technologies in transportation infrastructure projects to a greater degree
+than in previous legislation. In addition, various other funding mechanisms exist to support transportation infrastructure and related projects. These include bonds, dedicated sales and gas tax
+measures and other alternative funding sources. We believe the overall expansion of our Transportation Systems segment in the future will at least in part be dependent on the federal government's use
+of funds under the federal highway bill.
+Delays in the release of funding may prolong uncertainty regarding the allotment of transportation funds in federal, state and local budgets. We believe that prolonged uncertainty has adversely
+impacted in the past, and may adversely impact in the future, our Transportation Systems revenues and our overall financial performance in future periods. 
+iPerform 
+Our iPerform segment, formed during the first quarter of our fiscal year ended March 31, 2013 ("Fiscal 2013"), includes our
+performance measurement and information management solutions, including all of the operations of Berkeley Transportation Systems, Inc. ("BTS"), which we acquired in November 2011. BTS
+specializes in transportation performance measurement. The BTS performance measurement system leverages its real-time data collection, diagnostic, fusion and warehousing platform to aggregate and
+compute performance measurements. During the fiscal year ended March 31, 2012 ("Fiscal 2012"), we began the development of iPeMS (formerly, IterisPeMS). iPeMS is a state-of-the-art information
+management software suite that utilizes a wide range of data resources and analytical techniques to determine current and future traffic patterns, permitting the effective performance analysis and
+management of traffic infrastructure resources. This information can then be analyzed by traffic professionals to measure how a transportation network is performing and to identify potential areas of
+improvement. iPeMS is also capable of providing users with predictive traffic analytics and easy-to-use visualization and animation features based on historical traffic conditions. 
+4 
+Table of Contents 
+The
+iPerform segment also includes the operations of Meridian Environmental Technology, Inc. ("MET"), which we acquired in January 2011. MET specializes in 511/ advanced traveler
+information systems as well as ClearPath Weather management tools that allow users to create solutions to meet roadway maintenance decision needs. With the addition of MET, we have experienced
+seasonality particularly related to certain ClearPath Weather services in our first and second fiscal quarters, mainly because ClearPath Weather services are generally not required in the summer
+months when weather conditions are typically less severe. 
+iPerform
+is a market leader in performance management solutions for federal and state organizations. We intend to use our strong brand and deep experience in the traffic management
+market, as well as our market-specific intellectual property, to expand our leadership in data aggregation and analytics. By increasing investments in both technical and market development, we plan to
+focus on expanding the scope of our public sector solutions into the commercial marketplace. 
+Going
+forward, iPerform's solutions are expected to include incident management applications, arterial solutions, predictive traffic, and weather-based data and analytics for both public
+and commercial markets. We plan to fund these investments through internally generated cash flow from our Roadway Sensors and Transportation Systems operating segments, as well as revenues from our
+iPerform segment and our available cash if necessary. 
+Sales, Marketing and Principal Customers 
+We sell our Roadway Sensors products through direct and indirect sales channels. In the territories where we sell direct, we use a
+combination of our own sales personnel and an outside sales organization to sell, oversee installations and set-up issues and support our products. Our indirect sales channels are comprised of a
+network of independent dealers in the U.S. and certain foreign locations, who sell integrated systems and related products to the traffic management market. Our independent dealers are trained in, and
+primarily responsible for, sales, installation, set-up and support of our products, maintain an inventory of demonstration traffic products from various manufacturers and sell directly to government
+agencies and installation contractors. These dealers often have long-term arrangements with local government agencies in their respective territories for the supply of various products for the
+construction and renovation of traffic intersections, and are generally well-known suppliers of high-quality ITS products to the traffic management market. We periodically hold technical training
+classes for our dealers and end users and maintain a full-time staff of customer support technicians throughout the U.S. to provide technical assistance when needed. When appropriate, we have the
+ability to modify or make changes to our dealer network to accommodate the needs of the market and our customer base. 
+We
+market and sell our Transportation Systems services and solutions and iPerform solutions directly to government agencies pursuant to negotiated contracts that involve competitive
+bidding and specific qualification requirements. Most of our contracts are with federal, state and municipal customers and generally provide for cancellation or renegotiation at the option of the
+customer upon reasonable notice and fees paid for modification. We generally use selected members of our engineering, science and information technology teams on a regional basis to serve in sales and
+business development functions. Our contracts generally involve long lead times and require extensive specification development, evaluation and price negotiations. Additionally, we plan to focus on
+expanding the scope of our iPerform public sector solutions to sell into the commercial marketplace. 
+A
+large portion of our revenues are derived from sales to federal, state and local government agencies. We currently have, and historically have had, a diverse customer base. For our
+fiscal year ended March 31, 2014 ("Fiscal 2014"), one individual customer represented approximately 11% of our total revenues and no other individual customer represented greater than 10% of
+our total revenues. For Fiscal 2013, one individual customer represented approximately 13% of our total revenues and no 
+5 
+Table of Contents 
+other
+individual customer represented greater than 10% of our total revenues. For Fiscal 2012, no individual customer represented greater than 10% of our total revenues. Also refer to Note 13
+of Notes to Consolidated Financial Statements, included in Part IV, Item 15 of this report. 
+Manufacturing and Materials 
+We use contract manufacturers to build subassemblies that are used in our Roadway Sensors products. Additionally, we procure certain
+components from qualified suppliers, both locally and globally, and generally use multi-sourcing strategies when technically and economically feasible to mitigate supply risk. These subassemblies and
+components are typically delivered to our Santa Ana, California facility where they go through final assembly and testing prior to shipment to our customers. Our key suppliers include CTS Electronics
+Manufacturing Solutions, Inc., Sony Electronics, Inc. and LG Electronics, Inc. Our manufacturing activities are conducted in approximately 9,000 square feet of space at our Santa
+Ana facility. Production volume at our subcontractors is based upon quarterly forecasts that we generally adjust on a monthly basis to control inventory levels. We typically do not manufacture any of
+the hardware used in the transportation management and traveler information systems that we design and implement. Our production facility is currently ISO 9001 certified. 
+Customer Support and Services 
+We provide warranty service and support for our products, as well as follow-up service and support for which we charge separately. Such
+service revenue was not a material portion of our total revenues for each of Fiscal 2014, Fiscal 2013 and Fiscal 2012. We believe customer support is a key competitive factor. 
+Backlog 
+Our total backlog of unfulfilled firm orders was approximately $35.6 million as of March 31, 2014, which included
+$27.6 million related to Transportation Systems. Substantially the entire backlog for Roadway Sensors is expected to be recognized as revenue in the
+fiscal year ending March 31, 2015 ("Fiscal 2015"). In the past three fiscal years, we have recognized approximately 50% to 70% of our Transportation Systems backlog as of the end of a fiscal
+year in the subsequent fiscal year, and currently expect that trend to continue for the near future for both Transportation Systems and iPerform. 
+At
+March 31, 2013, we had backlog of approximately $38.6 million, which included $32.2 million related to Transportation Systems. 
+The
+timing and realization of our backlog is subject to the inherent uncertainties of doing business with federal, state and local governments, particularly in view of budgetary
+constraints, cut-backs and other delays or reallocations of funding that these entities typically face. 
+In
+addition, pursuant to the customary terms of our agreements with government contractors and other customers, our customers can generally cancel or reschedule orders with little or no
+penalties. Lead times for the release of purchase orders often depend upon the scheduling and forecasting practices of our individual customers, which also can affect the timing of the conversion of
+our backlog into revenues. For these reasons, among others, our backlog at a particular date may not be indicative of our future revenues, in particular for our Roadway Sensors segment. 
+Product Development 
+Most of our product development activities are conducted at our principal facilities in Santa Ana, California. Our research and
+development costs and expenses were approximately $4.0 million for Fiscal 2014, $3.1 million for Fiscal 2013 and $3.2 million for Fiscal 2012. We expect to continue to 
+6 
+Table of Contents 
+pursue
+various product development programs and incur research and development expenditures in future periods. 
+We
+believe our engineering and product development capabilities are a competitive strength. We strive to continue to develop new products to meet the needs of the ever-changing ITS
+market as well as enhance and refine our existing product lines. Since 2008, our Roadway Sensors segment has
+introduced our VantageNext, Vantage Vector, VersiCam and VersiCam wireless products, P10, P100, RZ-4 advanced camera and our RZ-4 advanced wide dynamic range camera, which significantly improve video
+detection performance in certain harsh lighting conditions, as well as upgrades to our Abacus and VantageView products. Additionally, during Fiscal 2012, we began development of our software based
+iPeMS performance measurement system, which continued through Fiscal 2014 and will continue during Fiscal 2015. We also plan to focus our development efforts on our ClearPath Weather and ClearPath
+Agriculture products. We believe that developing new offerings across our segments and enhancing, refining and marketing our existing products is a key component of strong organic growth and
+profitability. 
+Competition 
+We generally face significant competition in each of our target markets. Increased competition may result in price reductions, reduced
+gross margins and loss of market share, any of which could have a material adverse effect on our business, financial condition and results of operations. 
+In
+the market for our Roadway Sensors vehicle detection products, we compete with manufacturers and distributors of other above ground video camera detection systems and other
+non-intrusive detection devices, including microwave, infrared, radar, ultrasonic and magnetic detectors, as well as manufacturers and installers of in-pavement inductive loop products, which have
+historically, and currently continue to be, the predominant detection system in this market. 
+The
+markets in which our Transportation Systems segment operates is highly fragmented and subject to evolving national and regional quality, operations and safety standards. Our
+competitors vary in number, scope and breadth of the products and services they offer. Our competitors in advanced Transportation Systems include national corporations that generally offer expertise
+in traveler information, integration and transportation management. Our competitors in transportation engineering, planning and design include major regional firms, as well as many smaller local
+engineering firms. 
+The
+markets in which our iPeform segment operates vary from public sector customers who focus on performance measurement systems to help measure and manage the effectiveness of their
+transportation systems to commercial sector customers who ingest and disseminate traffic and weather related data, information and analytics through various consumer outlets. Our competitors vary in
+number, scope and breadth of the products and services they offer. In the public sector, we compete with some of the same transportation engineering, planning and design firms that also compete with
+our Transportation Systems segment. In the commercial sector, we compete with a variety of entities that currently provide traffic and/or weather related data to that market. 
+In
+general, the markets for the products and services we offer are highly competitive and are characterized by rapidly changing technology and evolving standards. Many of our current and
+prospective competitors have longer operating histories, greater name recognition, access to larger customer bases and significantly greater financial, technical, manufacturing, distribution and
+marketing resources than us. As a result, they may be able to adapt more quickly to new or emerging standards or technologies or to devote greater resources to the promotion and sale of their
+products. It is also possible that new competitors or alliances among competitors could emerge and rapidly acquire significant market share. We believe that our ability to compete effectively in our
+target markets will depend on a number of factors, including the success and timing of our new product development, the 
+7 
+Table of Contents 
+compatibility
+of our products with a broad range of computing systems, product quality and performance, reliability, functionality, price and service and technical support. Our failure to provide
+services and develop and market products that compete successfully with those of other suppliers and consultants in our target markets would have a material adverse effect on our business, financial
+condition and results of operations. 
+Intellectual Property and Proprietary Rights 
+Our ability to compete effectively depends in part on our ability to develop and maintain the proprietary aspects of our technology.
+Our policy is to obtain appropriate proprietary rights protection for any potentially significant new technology acquired or developed by us. We currently hold three U.S. patents, four foreign patent
+applications, six patent applications in the United States ("U.S."), and eight provisional patent filings. One U.S. patent, which expires in May 2019, is for general technology related to CMOS
+sensors. Two U.S. patents, which expire between 2014 and 2029, three foreign patent applications, three U.S. patent applications, and one provisional patent filing relate specifically to our Roadway
+Sensors technology. One pending foreign patent, three U.S. patent applications, and seven provisional patent filings relate specifically to our iPerform technology. We cannot be certain that any new
+patents will be granted pursuant to these or subsequent patent applications or provisional patent filings. 
+In
+addition to patent laws, we rely on copyright and trade secret laws to protect our proprietary rights. We attempt to protect our trade secrets and other proprietary information
+through agreements with customers and suppliers, proprietary information agreements with our employees and consultants, and other similar measures. We do not have any material licenses or trademarks
+other than those relating to product names. We cannot be certain that we will be successful in protecting our proprietary rights. While we believe our patents, patent applications, software and other
+proprietary know-how have value; changing technology makes our future success dependent principally upon our ability to successfully achieve continuing innovation. 
+Litigation
+may be necessary in the future to enforce our proprietary rights, to determine the validity and scope of the proprietary rights of others, or to defend us against claims of
+infringement or invalidity by others. An adverse outcome in such litigation or similar proceedings could subject us to significant liabilities to third parties, require disputed rights to be licensed
+from others or require us to cease marketing or using certain products, any of which could have a material adverse effect on our business, financial condition and results of operations. In addition,
+the cost of addressing any intellectual property litigation claim, both in legal fees and expenses, as well as from the diversion of management's resources, regardless of whether the claim is valid,
+could be significant and could have a material adverse effect on our business, financial condition and results of operations. 
+Employees 
+We refer to our employees as associates. As of March 31, 2014, we employed a total of 266 associates (of which 239 are
+full-time), including 56 associates in general management, administration and finance; 26 associates in sales and marketing; 154 associates in engineering and product development;
+14 associates in operations, manufacturing and quality assurance; and 16 associates in customer service. None of our associates are represented by a labor union, and we have never
+experienced a work stoppage. We believe our relations with our associates are good. 
+Government Regulation 
+Our manufacturing operations are subject to various federal, state and local laws and regulations, including those restricting the
+discharge of materials into the environment. We are not involved in any pending or, to our knowledge, threatened governmental proceedings, which would require curtailment 
+8 
+Table of Contents 
+of
+our operations because of such laws and regulations. We continue to expend funds in connection with our compliance with applicable environmental regulations. These expenditures have not, however,
+been significant in the past, and we do not expect any significant expenditure in the near future. Currently, compliance with foreign laws has not had a material impact on our business and is not
+expected to have a material impact in the near future.
\ No newline at end of file
diff --git a/raw/filings/0000350868/2013/0001047469-14-007351/item13.txt b/raw/filings/0000350868/2013/0001047469-14-007351/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..0af485288a6bb688f3490b71cbedcbd6d038da72
--- /dev/null
+++ b/raw/filings/0000350868/2013/0001047469-14-007351/item13.txt
@@ -0,0 +1,28 @@
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+Certain Transactions 
+Since April 1, 2012, other than the agreements and transactions described in Part III, Item 11 and the
+transactions described below, there has not been, nor is there any proposed transaction, where we (or any of our subsidiaries) were or will be a party in which the amount involved exceeded or will
+exceed the lesser of $120,000 or the average of our total assets at year end for the last two fiscal years and in which any director, executive officer, holder of more than 5% of any class of our
+voting securities, or any member of the immediate family of any of the foregoing persons had or will have a direct or indirect material interest. 
+We
+previously subleased office space to Maxxess Systems, Inc. ("Maxxess"), one of our former subsidiaries that we sold in September 2003 and is currently owned by an investor
+group that includes
+Mr. Daly, a current director of Iteris and the Chief Executive Officer of Maxxess, and Joel Slutzky, a former director of Iteris. The sublease terminated in September 2007, at which time
+Maxxess owed us an aggregate of $274,000 related to this sublease and certain ancillary corporate services that we provided to Maxxess. In August 2009, Maxxess executed a promissory note payable to us
+for $274,000. The promissory note accrued interest at a rate of 6% per annum, compounded annually, with such interest to be paid annually on the first business day of each calendar year. Payments
+under the note may be made in bona fide services rendered by Maxxess to us to the extent such services and amounts are pre-approved in writing by us. All amounts outstanding under the note was to
+become due and payable on the earliest of (i) August 10, 2014, (ii) a change of control in Maxxess, or (iii) a financing by Maxxess resulting in gross proceeds of at least
+$10 million. 
+On
+July 23, 2013, the promissory note with Maxxess was amended and restated. The amended and restated note bears interest at a rate of 6% per annum, compounded annually, with
+accrued interest to 
+51 
+Table of Contents 
+be
+paid quarterly on the first business day of each calendar quarter. Payments under the amended and restated note may only be made in cash and all amounts outstanding will become due and payable on
+the earliest of (i) August 10, 2016, (ii) a change of control in Maxxess or (iii) a financing by Maxxess resulting in gross proceeds of at least $10 million. As of
+March 31, 2014 and as of August 15, 2014, approximately $259,000 of the original principal balance was outstanding and payable to us. During each of Fiscal 2013 and Fiscal 2014, interest
+payments totaling approximately $16,000 were made by Maxxess. We have previously fully reserved for amounts owed to us by Maxxess and all outstanding principal remains fully reserved. 
+Director Independence 
+The Board of Directors has determined that each of Messrs. Char, Daly, Miner, Mooney, Thomas and Williams satisfies the
+requirements for "independence" under the listing standards of NYSE MKT.
\ No newline at end of file
diff --git a/raw/filings/0000350868/2013/0001047469-14-007351/item9a.txt b/raw/filings/0000350868/2013/0001047469-14-007351/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..d2084c2791f699cde9846a532ce991cb8301f1f6
--- /dev/null
+++ b/raw/filings/0000350868/2013/0001047469-14-007351/item9a.txt
@@ -0,0 +1,59 @@
+ITEM 9A. CONTROLS AND PROCEDURES 
+(a) Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934, as
+amended
+(the "Exchange Act"), as of the end of the period covered by this Annual Report on Form 10-K, management evaluated, with the participation of our President and Chief Executive Officer and our
+Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act). Based upon their
+evaluation of these disclosure controls and procedures, the President and Chief Executive Officer and the Chief Financial Officer have concluded that our disclosure controls and procedures were not
+effective as of March 31, 2014 because of a material weakness in our internal controls over financial reporting ("ICFR") as described below. 
+(b) Material weakness in ICFR. A material weakness is a deficiency, or combination of deficiencies, in ICFR, such that there is a
+reasonable
+possibility that a material misstatement of the Company's annual or interim financial statements will not be prevented or detected on a timely basis. Management has identified the following
+significant deficiencies that constitute a material weakness in our ICFR as of March 31, 2014: 
+37 
+Table of Contents 
+• The Company has not designed appropriate internal controls to analyze each consulting contract to determine if it should
+be accounted for in accordance with contract accounting (FASB Accounting Standards Codification ("ASC") 605-35, Construction-Type and Production-Type
+Contracts ) or as a multiple element arrangement (ASC 605-25, Revenue Recognition: Multiple-Element Arrangements ) and the proper
+revenue recognition policy to apply. 
+• The Company has not consistently evaluated how an arrangement or a contract should be bifurcated into separate elements
+or how separate elements within such arrangements are properly combined in accordance with GAAP. 
+• The Company has not designed sufficient controls to consider the impact of software elements and if such elements result
+in the arrangement or portions of the arrangement to be software elements to be accounted for in accordance with ASC 985-605, Software: Revenue
+Recognition . 
+(c) Plan for remediation of material weakness. Management is actively engaged in the planning for, and implementation of, remediation
+efforts to
+address the material weakness identified above. Management has or intends to take the following actions to address the material weakness: 
+• Management has created a new position (Director, Revenue Recognition) to perform the proper analysis for multiple element
+contracts, software elements, construction accounting, and other technical accounting issues. 
+• Management began implementing processes and controls during the first quarter of Fiscal 2015 to evaluate multiple
+deliverable arrangements to ensure revenue is recognized and accounted for in accordance with GAAP. 
+• Management has performed a detailed review of revenues resulting from contracts as of March 31, 2014 and recorded
+the necessary adjustments. 
+(d) Changes in internal control. Except as discussed above, there was no change in our internal control over financial reporting that
+occurred during
+the fourth quarter of Fiscal 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. 
+Inherent Limitations on Internal Control 
+A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives
+of the control system are met. Further, the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can
+provide absolute assurance that all control issues and instances of management override or improper acts, if any, have been detected. These inherent limitations include the realities that judgments in
+decision making can be faulty, and that breakdowns can occur because of simple errors. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more
+people, or by management override of the control. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and there can be no
+assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to
+management override, error or improper acts may occur and not be detected. Any resulting misstatement or loss may have an adverse and material effect on our business, financial condition and results
+of operations. 
+Management's Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control
+system was designed to provide reasonable assurance to 
+38 
+Table of Contents 
+management
+and our Board of Directors regarding the effectiveness of our internal control processes over the preparation and fair presentation of published financial statements. 
+We
+have assessed the effectiveness of our internal controls over financial reporting as of March 31, 2014. In making this assessment, we used the criteria set forth by the
+Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework (2006) . Based on our assessment,
+we believe that, as of March 31, 2014, our internal control over financial reporting was not effective due to a material weakness related to our controls over the accounting for consulting
+services revenues. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a
+material misstatement of the Company's annual or interim financial statements will not be prevented or detected on a timely basis. 
+This
+annual report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Such a report is not
+required pursuant to the rules of the SEC applicable to smaller reporting companies.
\ No newline at end of file
diff --git a/raw/filings/0000350868/2013/0001047469-14-007351/rp_note.txt b/raw/filings/0000350868/2013/0001047469-14-007351/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000350868/2013/0001047469-14-007351/rpt_disclosure.txt b/raw/filings/0000350868/2013/0001047469-14-007351/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..0af485288a6bb688f3490b71cbedcbd6d038da72
--- /dev/null
+++ b/raw/filings/0000350868/2013/0001047469-14-007351/rpt_disclosure.txt
@@ -0,0 +1,28 @@
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+Certain Transactions 
+Since April 1, 2012, other than the agreements and transactions described in Part III, Item 11 and the
+transactions described below, there has not been, nor is there any proposed transaction, where we (or any of our subsidiaries) were or will be a party in which the amount involved exceeded or will
+exceed the lesser of $120,000 or the average of our total assets at year end for the last two fiscal years and in which any director, executive officer, holder of more than 5% of any class of our
+voting securities, or any member of the immediate family of any of the foregoing persons had or will have a direct or indirect material interest. 
+We
+previously subleased office space to Maxxess Systems, Inc. ("Maxxess"), one of our former subsidiaries that we sold in September 2003 and is currently owned by an investor
+group that includes
+Mr. Daly, a current director of Iteris and the Chief Executive Officer of Maxxess, and Joel Slutzky, a former director of Iteris. The sublease terminated in September 2007, at which time
+Maxxess owed us an aggregate of $274,000 related to this sublease and certain ancillary corporate services that we provided to Maxxess. In August 2009, Maxxess executed a promissory note payable to us
+for $274,000. The promissory note accrued interest at a rate of 6% per annum, compounded annually, with such interest to be paid annually on the first business day of each calendar year. Payments
+under the note may be made in bona fide services rendered by Maxxess to us to the extent such services and amounts are pre-approved in writing by us. All amounts outstanding under the note was to
+become due and payable on the earliest of (i) August 10, 2014, (ii) a change of control in Maxxess, or (iii) a financing by Maxxess resulting in gross proceeds of at least
+$10 million. 
+On
+July 23, 2013, the promissory note with Maxxess was amended and restated. The amended and restated note bears interest at a rate of 6% per annum, compounded annually, with
+accrued interest to 
+51 
+Table of Contents 
+be
+paid quarterly on the first business day of each calendar quarter. Payments under the amended and restated note may only be made in cash and all amounts outstanding will become due and payable on
+the earliest of (i) August 10, 2016, (ii) a change of control in Maxxess or (iii) a financing by Maxxess resulting in gross proceeds of at least $10 million. As of
+March 31, 2014 and as of August 15, 2014, approximately $259,000 of the original principal balance was outstanding and payable to us. During each of Fiscal 2013 and Fiscal 2014, interest
+payments totaling approximately $16,000 were made by Maxxess. We have previously fully reserved for amounts owed to us by Maxxess and all outstanding principal remains fully reserved. 
+Director Independence 
+The Board of Directors has determined that each of Messrs. Char, Daly, Miner, Mooney, Thomas and Williams satisfies the
+requirements for "independence" under the listing standards of NYSE MKT.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2003/0000950134-04-003498/filing.txt b/raw/filings/0000928022/2003/0000950134-04-003498/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..0670f658c3d63e65541dd92cbb51d2d3bd6fa8ce
--- /dev/null
+++ b/raw/filings/0000928022/2003/0000950134-04-003498/filing.txt
@@ -0,0 +1,4193 @@
+10-K
+1
+d13486e10vk.txt
+FORM 10-K
+SECURITIES AND EXCHANGE COMMISSION
+WASHINGTON, D.C. 20549
+FORM 10-K
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
+THE SECURITIES EXCHANGE ACT OF 1934
+FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003
+COMMISSION FILE NUMBER 001-14039
+CALLON PETROLEUM COMPANY
+(Exact name of Registrant as specified in its charter)
+DELAWARE 64-0844345
+(State or other jurisdiction of (I.R.S. Employer
+incorporation or organization) Identification No.)
+200 NORTH CANAL STREET
+NATCHEZ, MISSISSIPPI 39120 (601) 442-1601
+(Address of Principal Executive (Registrant's telephone number
+Offices)(Zip Code) including area code)
+Securities registered pursuant to Section 12(b) of the Act:
+TITLE OF EACH CLASS NAME OF EXCHANGE ON WHICH REGISTERED
+----------------------------------------- ------------------------------------
+Convertible Exchangeable Preferred Stock, New York Stock Exchange
+Series A, Par Value $.01 Per Share
+Common Stock, Par Value $.01 Per Share New York Stock Exchange
+Preferred Stock Purchase Rights New York Stock Exchange
+11% Senior Subordinated Notes due 2005 New York Stock Exchange
+Securities registered pursuant to Section 12(g) of the Act: NONE
+Indicate by check mark whether the Registrant (1) has filed all reports required
+to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
+the preceding 12 months (or for such shorter period that the Registrant was
+required to file such reports), and (2) has been subject to such filing
+requirements for the past 90 days. Yes |X|. No | |.
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
+of Regulation S-K is not contained herein, and will not be contained, to the
+best of Registrant's knowledge, in definitive proxy or information statements
+incorporated by reference in Part III of this Form 10-K or any amendment to this
+Form 10-K. |X|
+Indicate by check mark whether the registrant is an accelerated filer (as
+defined in Exchange Act Rule 12b-2). Yes |X| No.| |.
+The aggregate market value of the voting and non-voting common equity held by
+nonaffiliates of the registrant was approximately $78.8 million as of June 30,
+2003 (based on the last reported sale price of such stock on the New York Stock
+Exchange on such date of $7.12).
+As of March 4, 2004, there were 13,976,411 shares of the Registrant's Common
+Stock, par value $.01 per share, outstanding.
+Document incorporated by reference: Portions of the definitive Proxy Statement
+of Callon Petroleum Company (to be filed no later than 120 days after December
+31, 2003) relating to the Annual Meeting of Stockholders to be held on May 6,
+2004, which is incorporated into Part III of this Form 10-K.
+1
+PART I.
+ITEM 1 AND 2. BUSINESS AND PROPERTIES
+OVERVIEW
+Callon Petroleum Company has been engaged in the exploration, development,
+acquisition and production of oil and gas properties since 1950. Our properties
+are geographically concentrated primarily offshore in the Gulf of Mexico and
+onshore in Louisiana and Alabama. We were incorporated under the laws of the
+state of Delaware in 1994 and succeeded to the business of a publicly traded
+limited partnership, a joint venture with a consortium of European institutional
+investors and an independent energy company owned by members of current
+management. As used herein, the "Company," "Callon," "we," "us," and "our" refer
+to Callon Petroleum Company and its predecessors and subsidiaries unless the
+context requires otherwise.
+In 1989, we began increasing our reserves through the acquisition of producing
+properties that were geologically complex, had (or were analogous to fields
+with) an established production history from stacked pay zones and were
+candidates for exploitation. We focused on reducing operating costs and
+implementing production enhancements through the application of technologically
+advanced production and recompletion techniques.
+Over the past eight years, we have also placed emphasis on the acquisition of
+acreage with exploration and development drilling opportunities in the Gulf of
+Mexico shelf and deepwater areas. At December 31, 2003 we owned working
+interests in a total of 73 blocks/leases covering 157,000 net acres. We joined
+with other industry partners, primarily Murphy Exploration and Production, Inc.,
+to explore federal offshore blocks acquired in the Gulf of Mexico. We perform
+extensive geological and geophysical studies using computer-aided exploration
+techniques (CAEX), including, where appropriate, the acquisition of 3-D seismic
+or high-resolution 2-D data to facilitate these efforts. We continue to develop
+prospects on the shelf through our 3-D seismic partnership using AVO technology.
+In 1998, we began exploration in the Gulf of Mexico deepwater area (generally
+900 to 5,500 feet of water). In the fourth quarter of 2003, our first two
+deepwater projects, the Medusa and Habanero fields, began production. Please see
+"Significant Properties" for a more detailed discussion.
+We ended the year 2003 with estimated net proved reserves of 217 billion cubic
+feet of natural gas equivalent ("Bcfe"). This represents a decrease of 8% from
+2002 year-end estimated net proved reserves of 236 Bcfe.
+The major focus of our future operations is expected to continue to be the
+exploration for and development of oil and gas properties, primarily in the Gulf
+of Mexico.
+AVAILABILITY OF REPORTS
+All of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current
+reports on Form 8-K, and amendments to such reports as well as other filings we
+make pursuant to Section 13(a) and 15(d) of the Securities Exchange Act of 1934
+are available free of charge on our Internet website. The address of our
+Internet website is www.callon.com. Our SEC filings are available on our website
+as soon as they are posted to the EDGAR database on the SEC's website.
+2
+BUSINESS STRATEGY
+Our goal is to increase shareholder value by increasing our reserves,
+production, cash flow and earnings. We seek to achieve these goals through the
+following strategies:
+- focus on Gulf of Mexico exploration with a balance between shelf and
+deepwater areas using the latest available technology;
+- aggressively explore our existing prospect inventory;
+- replenish our prospect inventory with increasing emphasis on
+prospect generation using AVO technology;
+- achieve moderate increases in current production levels through
+continued shelf exploration; and
+- achieve significant increases in longer-term production levels
+through development of deepwater discoveries and ongoing deepwater
+exploration.
+EXPLORATION AND DEVELOPMENT ACTIVITIES
+Capital expenditures for exploration and development costs related to oil and
+gas properties totaled approximately $50 million in 2003. We incurred
+approximately $32 million in the Gulf of Mexico deepwater area primarily for
+development costs at our Habanero and Medusa discoveries. Interest of
+approximately $5 million and general and administrative costs allocable directly
+to exploration and development projects of $8 million were capitalized in 2003.
+Our Gulf of Mexico shelf area expenditures account for the remainder of the
+total capital expended.
+SEC INQUIRIES REGARDING RESERVE INFORMATION
+Beginning in October 2002, we received a series of inquiries from the SEC
+regarding our Annual Report on Form 10-K for the year ended December 31, 2001
+requesting supplemental information concerning operations in the Gulf of Mexico.
+The comment letters requested information about the procedures used to classify
+the deepwater reserves as proved and requested that our financial statements be
+restated to reflect the removal of the reserves attributable to the Boomslang
+discovery as proved for all prior periods during which such reserves were
+reported as proved. We have reviewed the SEC comments with our independent
+petroleum reserve engineers, Huddleston & Co., Inc. of Houston, Texas. Both
+Huddleston & Co. and we believe that such deepwater reserves are properly
+classified as proved. We have responded to all the inquiries from the SEC.
+Based on our discussions with others in the oil and gas business, we believe
+that the SEC is reviewing generally the procedures used by reserve engineers to
+classify oil and gas reserves as proved in the deepwater areas of the Gulf of
+Mexico. In particular, the SEC appears to indicate that it is not appropriate to
+classify reserves as proved without conducting a "flow test." It has not been
+our practice to conduct a flow test on our deepwater properties prior to
+classifying the reserves as proved. We believe, and have been advised by
+Huddleston & Co., that our procedures for classifying our deepwater reserves as
+proved are in accordance with SEC rules and industry practices.
+RISK FACTORS
+A DECREASE IN OIL AND GAS PRICES MAY ADVERSELY AFFECT OUR RESULTS OF OPERATIONS
+AND FINANCIAL CONDITION. Our success is highly dependent on prices for oil and
+gas, which are extremely volatile. Any
+3
+substantial or extended decline in the price of oil or gas would have a material
+adverse effect on us. Oil and gas markets are both seasonal and cyclical. The
+prices of oil and gas depend on factors we cannot control such as weather,
+economic conditions, and levels of production, actions by OPEC and other
+countries and government actions. Prices of oil and gas will affect the
+following aspects of our business:
+- our revenues, cash flows and earnings;
+- the amount of oil and gas that we are economically able to produce;
+- our ability to attract capital to finance our operations and the
+cost of the capital;
+- the amount we are allowed to borrow under our senior secured credit
+facility;
+- the value of our oil and gas properties; and
+- the profit or loss we incur in exploring for and developing our
+reserves.
+WE MAY BE REQUIRED TO RETROACTIVELY PAY ROYALTIES TO THE MINERALS MANAGEMENT
+SERVICE ON ONE OF OUR PROPERTIES WHICH COULD REDUCE REVENUES AND RESERVES. Our
+Medusa deepwater property is eligible for royalty suspensions pursuant to the
+Deep Water Royalty Relief Act. However, the federal offshore leases covering the
+property contain "price threshold" provisions for oil and gas prices. Under this
+"price threshold" provision, if the average monthly New York Mercantile Exchange
+(NYMEX) sales price for oil or gas during a fiscal year exceeds the price
+threshold for oil or gas, respectively, then royalties on the associated
+production must be paid to the Minerals Management Service (MMS) at the rate
+stipulated in the lease. The price thresholds are adjusted annually by the
+implicit price deflator for the GDP. The determination of whether or not
+royalties are due as a result of the average NYMEX price exceeding the price
+threshold is made during the first quarter of the succeeding year. Any royalty
+payments due must be made shortly after this determination is made. If a royalty
+payment is due for all production during a year as a result of exceeding the
+price threshold, the lessee is required to make monthly royalty payments during
+the succeeding fiscal year for the succeeding year's production. If at the end
+of any year the average NYMEX price is below the price threshold, the lessee can
+apply for a refund for any associated royalties paid during that year and the
+lessee will not be required to pay royalties monthly during the succeeding year
+for the succeeding year's production.
+The thresholds and the average NYMEX prices are calculated by the MMS. The
+average NYMEX price for 2003 was $31.08 per barrel of oil and $5.49 per MMBtu of
+natural gas. For the year ended December 31, 2003 the thresholds were $32.77 per
+barrel of oil and $4.10 per MMBtu of natural gas, subject to finalization of the
+adjustment for the 2003 GDP implicit price deflator. As a result we will pay
+royalties related to 2003 gas production for Medusa, which commenced production
+in late November 2003 and will make monthly royalty payments for 2004 gas
+production during 2004. Our actual liability for 2004 oil royalties, if any,
+cannot be determined until after the end of 2004.
+In the year succeeding the year in which any of our properties became subject to
+royalties as result of the average NYMEX price exceeding the price threshold,
+the portion of reserves attributable to potential future royalties would not be
+included in a year-end reserve report. However, if the average NYMEX prices were
+below the price thresholds in subsequent years, our reserves would be increased
+to reflect reserves previously attributed to future royalties. As a result,
+reported oil and gas reserves could materially increase or decrease, depending
+on the relation of price thresholds versus the average NYMEX prices. The
+reduction in our revenues resulting from an obligation to pay these royalties
+and subsequent reduction of our proved reserves could have a material adverse
+effect on our results of operations and financial condition. Our reserve report,
+as of December 31, 2003, excluded gas reserves for Medusa that are subject to
+MMS royalties as a result of the average 2003 NYMEX price for gas exceeding the
+price threshold. Oil reserves in this reserve report were not impacted since the
+2003 average NYMEX price was below the threshold.
+4
+OUR RESERVE INFORMATION REPRESENTS ESTIMATES THAT MAY TURN OUT TO BE INCORRECT
+IF THE ASSUMPTIONS UPON WHICH THESE ESTIMATES ARE BASED ARE INACCURATE. ANY
+MATERIAL INACCURACIES IN THESE RESERVE ESTIMATES OR UNDERLYING ASSUMPTIONS WILL
+MATERIALLY AFFECT THE QUANTITIES AND PRESENT VALUE OF OUR RESERVES. The process
+of estimating oil and gas reserves is complex. It requires interpretations of
+available technical data and various assumptions, including assumptions relating
+to economic factors. Any significant inaccuracies in these interpretations or
+assumptions could materially affect the estimated quantities and present value
+of reserves shown in this annual report.
+In order to prepare these estimates, we must project production rates and the
+timing of development expenditures. The assumptions regarding the timing and
+costs to commence production from our deepwater wells used in preparing our
+reserves are often subject to revisions over time as described under "our
+deepwater operations have special operational risks that may negatively affect
+the value of those assets." We must also analyze available geological,
+geophysical, production and engineering data, the extent, quality and
+reliability of which can vary. The process also requires us to make economic
+assumptions, such as oil and gas prices, drilling and operating expenses,
+capital expenditures, taxes and availability of funds. Therefore, estimates of
+oil and gas reserves are inherently imprecise.
+Actual future production, oil and gas prices, revenues, taxes, development
+expenditures, operating expenses and quantities of recoverable oil and gas
+reserves most likely will vary from our estimates. Any significant variance
+could materially affect the estimated quantities and present value of reserves
+shown in this report. In addition, we may adjust estimates of proved reserves to
+reflect production history, results of exploration and development, prevailing
+oil and gas prices and other factors, many of which are beyond our control.
+You should not assume that the present value of future net cash flows from our
+proved reserves referred to in this report is the current market value of our
+estimated oil and gas reserves. In accordance with SEC requirements, we
+generally base the estimated discounted future net cash flows from our proved
+reserves on prices and costs on the date of the estimate. Actual future prices
+and costs may differ materially from those used in the present value estimate.
+Information about reserves constitutes forward-looking information. See
+"Forward-Looking Statements" for information regarding forward-looking
+information. The discounted present value of our oil and gas reserves is
+prepared in accordance with guidelines established by the SEC. A purchaser of
+reserves would use numerous other factors to value our reserves. The discounted
+present value of reserves, therefore, does not represent the fair market value
+of those reserves.
+On December 31, 2003, approximately 53% of the discounted present value of our
+estimated net proved reserves were proved undeveloped. Proved undeveloped oil
+volumes represented 58% of total proved oil reserves. Substantially all of these
+proved undeveloped reserves were attributable to our deepwater properties.
+Development of these properties is subject to additional risks as described
+above.
+THE SEC MAY REQUIRE US TO BOOK RESERVES AS PROVED IN A MANNER THAT DIFFERS FROM
+OUR HISTORICAL PRACTICES AND CURRENT INDUSTRY STANDARDS, AND WHICH MAY RESULT IN
+A SIGNIFICANT DOWNWARD REVISION OF OUR PROVED RESERVES. As discussed above,
+beginning in October 2002 we received a series of inquiries from the SEC
+regarding our Annual Report on Form 10-K for the year ended December 31, 2001
+requesting supplemental information concerning our operations in the Gulf of
+Mexico. The comment
+5
+letters requested information about the procedures we used to classify our
+deepwater reserves as proved and requested that our financials be restated to
+reflect the removal of the Boomslang reserves as proved for all prior periods
+during which such reserves were reported as proved. We have reviewed the SEC
+comments with our independent petroleum reserve engineers, Huddleston & Co.,
+Inc. of Houston, Texas. Both Huddleston & Co. and we believe that such reserves
+were properly classified as proved. However, if the SEC decides to question our
+other deepwater properties and these reserves are ultimately required to be
+reclassified as not proved, our proved reserves will be materially reduced. If
+the SEC requires us to retroactively classify Boomslang as an unproved property
+through December 2002, we would be required to restate our financial position,
+results of operations, and supplemental oil and gas reserve data from 1998
+through 2002. A material reduction in our proved reserves could have a material
+adverse effect on our financial condition and results of operations. We have
+responded to all the inquiries from the SEC.
+UNLESS WE ARE ABLE TO REPLACE RESERVES WHICH WE HAVE PRODUCED, OUR CASH FLOWS
+AND PRODUCTION WILL DECREASE OVER TIME. Our future success depends upon our
+ability to find, develop and acquire oil and gas reserves that are economically
+recoverable. As is generally the case for Gulf properties, our producing
+properties usually have high initial production rates, followed by a steep
+decline in production. As a result, we must continually locate and develop or
+acquire new oil and gas reserves to replace those being depleted by production.
+We must do this even during periods of low oil and gas prices when it is
+difficult to raise the capital necessary to finance these activities and during
+periods of high operating costs when it is expensive to contract for drilling
+rigs and other equipment and personnel necessary to explore for oil and gas.
+Without successful exploration or acquisition activities, our reserves,
+production and revenues will decline rapidly. We cannot assure you that we will
+be able to find and develop or acquire additional reserves at an acceptable
+cost.
+A SIGNIFICANT PART OF THE VALUE OF OUR PRODUCTION AND RESERVES IS CONCENTRATED
+IN A SMALL NUMBER OF OFFSHORE PROPERTIES, AND ANY PRODUCTION PROBLEMS OR
+INACCURACIES IN RESERVE ESTIMATES RELATED TO THOSE PROPERTIES WOULD ADVERSELY
+IMPACT OUR BUSINESS. During 2003, 64% of our daily production came from two of
+our properties in the Gulf of Mexico. Moreover, one property accounted for 51%
+of our production during this period. In addition, at December 31, 2003, most of
+our proved reserves were located in four fields in the Gulf of Mexico, with
+approximately 94% of our total net proved reserves attributable to these
+properties. If mechanical problems, storms or other events curtailed a
+substantial portion of this production or if the actual reserves associated with
+any one of these producing properties are less than our estimated reserves, our
+results of operations and financial condition could be adversely affected.
+OUR FOCUS ON EXPLORATION PROJECTS INCREASES THE RISKS INHERENT IN OUR OIL AND
+GAS ACTIVITIES. Our business strategy focuses on replacing reserves through
+exploration, where the risks are greater than in acquisitions and development
+drilling. Although we have been successful in exploration in the past, we cannot
+assure you that we will continue to increase reserves through exploration or at
+an acceptable cost. Additionally, we are often uncertain as to the future costs
+and timing of drilling, completing and producing wells. Our drilling operations
+may be curtailed, delayed or canceled as a result of a variety of factors,
+including:
+- unexpected drilling conditions;
+- pressure or inequalities in formations;
+- equipment failures or accidents;
+- adverse weather conditions;
+- compliance with governmental requirements; and
+- shortages or delays in the availability of drilling rigs and the
+delivery of equipment.
+6
+WE DO NOT OPERATE ALL OF OUR PROPERTIES AND HAVE LIMITED INFLUENCE OVER THE
+OPERATIONS OF SOME OF THESE PROPERTIES, PARTICULARLY OUR DEEPWATER PROPERTIES.
+Our lack of control could result in the following:
+- the operator may initiate exploration or development on a faster or
+slower pace than we prefer;
+- the operator may propose to drill more wells or build more
+facilities on a project than we have funds for or that we deem
+appropriate, which may mean that we are unable to participate in the
+project or share in the revenues generated by the project even
+though we paid our share of exploration costs; and
+- if an operator refuses to initiate a project, we may be unable to
+pursue the project.
+Any of these events could materially reduce the value of our properties.
+OUR DEEPWATER OPERATIONS HAVE SPECIAL OPERATIONAL RISKS THAT MAY NEGATIVELY
+AFFECT THE VALUE OF THOSE ASSETS. Drilling operations in the deepwater area are
+by their nature more difficult and costly than drilling operations in shallow
+water. Deepwater drilling operations require the application of more advanced
+drilling technologies involving a higher risk of technological failure and
+usually have significantly higher drilling costs than shallow water drilling
+operations. Deepwater wells are completed using sub-sea completion techniques
+that require substantial time and the use of advanced remote installation
+equipment. These operations involve a high risk of mechanical difficulties and
+equipment failures that could result in significant cost overruns.
+In deepwater, the time required to commence production following a discovery is
+much longer than in shallow water and on-shore. Our deepwater discoveries and
+prospects will require the construction of expensive production facilities and
+pipelines prior to the beginning of production. We cannot estimate the costs and
+timing of the construction of these facilities with certainty, and the accuracy
+of our estimates will be affected by a number of factors beyond our control,
+including the following:
+- decisions made by the operators of our deepwater wells;
+- the availability of materials necessary to construct the facilities;
+- the proximity of our discoveries to pipelines; and
+- the price of oil and natural gas.
+Delays and cost overruns in the commencement of production will affect the value
+of our deepwater prospects and the discounted present value of reserves
+attributable to those prospects.
+COMPETITIVE INDUSTRY CONDITIONS MAY NEGATIVELY AFFECT OUR ABILITY TO CONDUCT
+OPERATIONS. We operate in the highly competitive areas of oil and gas
+exploration, development and production. We compete for the purchase of leases
+in the Gulf of Mexico from the U. S. government and from other oil and gas
+companies. These leases include exploration prospects as well as properties with
+proved reserves. Factors that affect our ability to compete in the marketplace
+include:
+- our access to the capital necessary to drill wells and acquire
+properties;
+- our ability to acquire and analyze seismic, geological and other
+information relating to a property;
+- our ability to retain the personnel necessary to properly evaluate
+seismic and other information relating to a property;
+7
+- the location of, and our ability to access, platforms, pipelines and
+other facilities used to produce and transport oil and gas
+production;
+- the standards we establish for the minimum projected return on an
+investment of our capital; and
+- the availability of alternate fuel sources.
+Our competitors include major integrated oil companies, substantial independent
+energy companies, and affiliates of major interstate and intrastate pipelines
+and national and local gas gatherers, many of which possess greater financial,
+technological and other resources than we do.
+OUR COMPETITORS MAY USE SUPERIOR TECHNOLOGY, WHICH WE MAY BE UNABLE TO AFFORD OR
+WHICH WOULD REQUIRE COSTLY INVESTMENT BY US IN ORDER TO COMPETE. Our industry is
+subject to rapid and significant advancements in technology, including the
+introduction of new products and services using new technologies. As our
+competitors use or develop new technologies, we may be placed at a competitive
+disadvantage, and competitive pressures may force us to implement new
+technologies at a substantial cost. In addition, our competitors may have
+greater financial, technical and personnel resources that allow them to enjoy
+technological advantages and may in the future allow them to implement new
+technologies before we can. We cannot be certain that we will be able to
+implement technologies on a timely basis or at a cost that is acceptable to us.
+One or more of the technologies that we currently use or that we may implement
+in the future may become obsolete, and we may be adversely affected. For
+example, marine seismic acquisition technology has been characterized by rapid
+technological advancements in recent years, and further significant
+technological developments could substantially impair our 3-D seismic data's
+value.
+WE MAY NOT BE ABLE TO REPLACE OUR RESERVES OR GENERATE CASH FLOWS IF WE ARE
+UNABLE TO RAISE CAPITAL. WE WILL BE REQUIRED TO MAKE SUBSTANTIAL CAPITAL
+EXPENDITURES TO DEVELOP OUR EXISTING RESERVES, AND TO DISCOVER NEW OIL AND GAS
+RESERVES. Historically, we have financed these expenditures primarily with cash
+from operations, proceeds from bank borrowings and proceeds from the sale of
+debt and equity securities. See "Management's Discussion and Analysis of
+Financial Condition and Results of Operations -- Liquidity and Capital
+Resources" for a discussion of our capital budget. We cannot assure you that we
+will be able to raise capital in the future. We also make offers to acquire oil
+and gas properties in the ordinary course of our business. If these offers are
+accepted, our capital needs may increase substantially.
+We expect to continue using our senior secured credit facility to borrow funds
+to supplement our available cash. The amount we may borrow under our senior
+secured credit facility may not exceed a borrowing base determined by the
+lenders under such facility based on their projections of our future production,
+future production costs, taxes, commodity prices and any other factors deemed
+relevant by our lenders. We cannot control the assumptions the lenders use to
+calculate our borrowing base. The lenders may, without our consent, adjust the
+borrowing base semiannually or in situations where we purchase or sell assets or
+issue debt securities. If our borrowings under the senior secured credit
+facility exceed the borrowing base, the lenders may require that we repay the
+excess. If this were to occur, we might have to sell assets or seek financing
+from other sources. Sales of assets could further reduce the amount of our
+borrowing base. We cannot assure you that we would be successful in selling
+assets or arranging substitute financing. If we were not able to repay
+borrowings under our senior secured credit facility to reduce the outstanding
+amount to less than the borrowing base, we would be in default under our senior
+secured credit facility. For a description of our senior secured credit facility
+and its principal terms and conditions, see "Management's Discussion and
+Analysis of Financial Condition and Results of Operations --Liquidity and
+Capital Resources."
+OUR DECISION TO DRILL A PROSPECT IS SUBJECT TO A NUMBER OF FACTORS AND WE MAY
+DECIDE TO ALTER OUR DRILLING SCHEDULE OR NOT DRILL AT ALL. We describe our
+current prospects and our plans to explore these
+8
+prospects in this annual report. A prospect is a property on which we have
+identified what our geoscientists believe, based on available seismic and
+geological information, to be indications of hydrocarbons. Our prospects are in
+various stages of evaluation, ranging from a prospect which is ready to drill to
+a prospect which will require substantial additional seismic data processing and
+interpretation. Whether we ultimately drill a prospect may depend on the
+following factors:
+- receipt of additional seismic data or the reprocessing of existing
+data;
+- material changes in oil or gas prices;
+- the costs and availability of drilling rigs;
+- the success or failure of wells drilled in similar formations or
+which would use the same production facilities;
+- availability and cost of capital;
+- changes in the estimates of the costs to drill or complete wells;
+- our ability to attract other industry partners to acquire a portion
+of the working interest to reduce exposure to costs and drilling
+risks; and
+- decisions of our joint working interest owners.
+We will continue to gather data about our prospects and it is possible that
+additional information may cause us to alter our drilling schedule or determine
+that a prospect should not be pursued at all. You should understand that our
+plans regarding our prospects are subject to change.
+WEATHER, UNEXPECTED SUBSURFACE CONDITIONS, AND OTHER UNFORESEEN OPERATING
+HAZARDS MAY ADVERSELY IMPACT OUR ABILITY TO CONDUCT BUSINESS. There are many
+operating hazards in exploring for and producing oil and gas, including:
+- our drilling operations may encounter unexpected formations or
+pressures, which could cause damage to equipment or personal injury;
+- we may experience equipment failures which curtail or stop
+production; and
+- we could experience blowouts or other damages to the productive
+formations that may require a well to be re-drilled or other
+corrective action to be taken.
+In addition, any of the foregoing may result in environmental damages for which
+we will be liable. Moreover, a substantial portion of our operations are
+offshore and are subject to a variety of risks peculiar to the marine
+environment such as capsizing, collisions, hurricanes and other adverse weather
+conditions. These conditions can cause substantial damage to facilities and
+interrupt production. Offshore operations are also subject to more extensive
+governmental regulation.
+We cannot assure you that we will be able to maintain adequate insurance at
+rates we consider reasonable to cover our possible losses from operating
+hazards. The occurrence of a significant event not fully insured or indemnified
+against could materially and adversely affect our financial condition and
+results of operations.
+WE MAY NOT HAVE PRODUCTION TO OFFSET HEDGES; BY HEDGING, WE MAY NOT BENEFIT FROM
+PRICE INCREASES. Part of our business strategy is to reduce our exposure to the
+volatility of oil and gas prices by hedging a portion of our production. In a
+typical hedge transaction, we will have the right to receive from the other
+parties to the hedge the excess of the fixed price specified in the hedge over a
+floating price based on a market index, multiplied by the quantity hedged. If
+the floating price exceeds the fixed price, we are required to pay the other
+parties this difference multiplied by the quantity hedged. We are required to
+pay the difference between the floating price and the fixed price when the
+floating price exceeds the fixed
+9
+price regardless of whether we have sufficient production to cover the
+quantities specified in the hedge. Significant reductions in production at times
+when the floating price exceeds the fixed price could require us to make
+payments under the hedge agreements even though such payments are not offset by
+sales of production. Hedging will also prevent us from receiving the full
+advantage of increases in oil or gas prices above the fixed amount specified in
+the hedge. We also enter into price "collars" to reduce the risk of changes in
+oil and gas prices. Under a collar, no payments are due by either party so long
+as the market price is above a floor set in the collar and below a ceiling. If
+the price falls below the floor, the counter-party to the collar pays the
+difference to us and if the price is above the ceiling, we pay the counter-party
+the difference. See "Quantitative and Qualitative Disclosures About Market
+Risks" for a discussion of our hedging practices.
+COMPLIANCE WITH ENVIRONMENTAL AND OTHER GOVERNMENT REGULATIONS COULD BE COSTLY
+AND COULD NEGATIVELY IMPACT PRODUCTION. Our operations are subject to numerous
+laws and regulations governing the operation and maintenance of our facilities
+and the discharge of materials into the environment or otherwise relating to
+environmental protection. For a discussion of the material regulations
+applicable to us, see "Federal Regulations," "State Regulations," and
+"Environmental Regulations." These laws and regulations may:
+- require that we acquire permits before commencing drilling;
+- restrict the substances that can be released into the environment in
+connection with drilling and production activities;
+- limit or prohibit drilling activities on protected areas such as
+wetlands or wilderness areas; and
+- require remedial measures to mitigate pollution from former
+operations, such as dismantling abandoned production facilities.
+Under these laws and regulations, we could be liable for personal injury and
+clean-up costs and other environmental and property damages, as well as
+administrative, civil and criminal penalties. We maintain limited insurance
+coverage for sudden and accidental environmental damages. We do not believe that
+insurance coverage for environmental damages that occur over time is available
+at a reasonable cost. Also, we do not believe that insurance coverage for the
+full potential liability that could be caused by sudden and accidental
+environmental damages is available at a reasonable cost. Accordingly, we may be
+subject to liability or we may be required to cease production from properties
+in the event of environmental damages.
+FACTORS BEYOND OUR CONTROL AFFECT OUR ABILITY TO MARKET PRODUCTION AND OUR
+FINANCIAL RESULTS. The ability to market oil and gas from our wells depends upon
+numerous factors beyond our control. These factors include:
+- the extent of domestic production and imports of oil and gas;
+- the proximity of the gas production to gas pipelines;
+- the availability of pipeline capacity;
+- the demand for oil and gas by utilities and other end users;
+- the availability of alternative fuel sources;
+- the effects of inclement weather;
+- state and federal regulation of oil and gas marketing; and
+- federal regulation of gas sold or transported in interstate
+commerce.
+10
+Because of these factors, we may be unable to market all of the oil or gas we
+produce. In addition, we may be unable to obtain favorable prices for the oil
+and gas we produce.
+IF OIL AND GAS PRICES DECREASE, WE MAY BE REQUIRED TO TAKE WRITEDOWNS OF THE
+CARRYING VALUE OF OUR OIL AND GAS PROPERTIES. We may be required to writedown
+the carrying value of our oil and gas properties when oil and gas prices are low
+or if we have substantial downward adjustments to our estimated net proved
+reserves, increases in our estimates of development costs or deterioration in
+our exploration results. Under the full cost method which we use to account for
+our oil and gas properties, the net capitalized costs of our oil and gas
+properties may not exceed the present value, discounted at 10%, of future net
+cash flows from estimated net proved reserves, using period end oil and gas
+prices or prices as of the date of our auditor's report, plus the lower of cost
+or fair market value of our unproved properties. If net capitalized costs of our
+oil and gas properties exceed this limit, we must charge the amount of the
+excess to earnings. This type of charge will not affect our cash flows, but will
+reduce the book value of our stockholders' equity. We review the carrying value
+of our properties quarterly, based on prices in effect as of the end of each
+quarter or at the time of reporting our results. Once incurred, a writedown of
+oil and gas properties is not reversible at a later date, even if prices
+increase.
+FORWARD-LOOKING STATEMENTS
+In this report, we have made many forward-looking statements. We cannot assure
+you that the plans, intentions or expectations upon which our forward-looking
+statements are based will occur. Our forward-looking statements are subject to
+risks, uncertainties and assumptions, including those discussed elsewhere in
+this report. Forward-looking statements include statements regarding:
+- our oil and gas reserve quantities, and the discounted present value
+of these reserves;
+- the amount and nature of our capital expenditures;
+- drilling of wells;
+- the timing and amount of future production and operating costs;
+- business strategies and plans of management; and
+- prospect development and property acquisitions.
+Some of the risks, which could affect our future results and could cause results
+to differ materially from those expressed in our forward-looking statements
+include:
+- general economic conditions;
+- the volatility of oil and natural gas prices;
+- the uncertainty of estimates of oil and natural gas reserves;
+- the impact of competition;
+- the availability and cost of seismic, drilling and other equipment;
+- operating hazards inherent in the exploration for and production of
+oil and natural gas;
+- difficulties encountered during the exploration for and production
+of oil and natural gas;
+- difficulties encountered in delivering oil and natural gas to
+commercial markets;
+- changes in customer demand and producers' supply;
+- the uncertainty of our ability to attract capital;
+- compliance with, or the effect of changes in, the extensive
+governmental regulations regarding the oil and natural gas business;
+- actions of operators of our oil and gas properties; and
+- weather conditions.
+11
+The information contained in this report, including the information set forth
+under the heading "Risk Factors," identifies additional factors that could
+affect our operating results and performance. We urge you to carefully consider
+these factors and the other cautionary statements in this report. Our
+forward-looking statements speak only as of the date made, and we have no
+obligation to update these forward-looking statements.
+CORPORATE OFFICES
+Our headquarters are located in Natchez, Mississippi, in approximately 51,500
+square feet of owned space, with a field office in Houston, Texas. We also
+maintain owned or leased field offices in the area of the major fields in which
+we operate properties or have a significant interest. Replacement of any of our
+leased offices would not result in material expenditures by us as alternative
+locations to our leased space are anticipated to be readily available.
+EMPLOYEES
+We had 94 employees as of December 31, 2003, none of whom are currently
+represented by a union. We believe that we have good relations with our
+employees. We employ eight petroleum engineers and seven petroleum
+geoscientists.
+FEDERAL REGULATIONS
+SALES OF NATURAL GAS. Effective January 1, 1993, the Natural Gas Wellhead
+Decontrol Act deregulated prices for all "first sales" of natural gas. Thus, all
+sales of gas by us may be made at market prices, subject to applicable contract
+provisions.
+TRANSPORTATION OF NATURAL GAS. The rates, terms and conditions applicable to the
+interstate transportation of natural gas by pipelines are regulated by the
+Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act ("NGA"),
+as well as under section 311 of the Natural Gas Policy Act ("NGPA"). Since 1985,
+the FERC has implemented regulations intended to make natural gas transportation
+more accessible to gas buyers and sellers on an open-access, non-discriminatory
+basis.
+In February, 2000, the FERC issued Order No. 637, a final rule designed to
+continue the restructuring of the gas industry initiated by an earlier final
+rule, Order No. 636, that instituted "open access" transportation. Order No. 637
+further revised the FERC's policies governing interstate pipeline transportation
+rates and penalties and further refined the regulatory framework governing
+transportation terms and conditions to improve open access transportation. The
+rule has been implemented on a pipeline-by-pipeline basis in individual
+compliance proceedings, many of which have been settled or have otherwise been
+terminated. A few proceedings, however, are still pending final resolution.
+In Order No. 644 issued November 13, 2003, the FERC imposed new standards of
+conduct, inter alia, for "all sellers for resale" marketing gas under blanket
+market certificates. The standards include a requirement of accurate reporting,
+if any, of the price of arm's-length deals to price index publishers and a
+requirement to notify the FERC as to whether the marketer reports transactions
+to price index publishers. In Order No. 2004, issued on November 25, 2003, the
+FERC issued standards of conduct covering regulated interstate pipelines and
+public utilities ("Transmission Providers") to govern the relationships between
+regulated Transmission Providers and all of their energy affiliates. Among other
+things, these measures are intended to
+12
+increase confidence and transparency in the gas market in the wake of recent
+events involving anticompetitive behavior and market abuse.
+On February 12, 2004, the FERC issued a notice of proposed rulemaking in Docket
+No. RM04-4 designed to standardize the procedures for determining the
+creditworthiness of shippers on interstate pipelines and to adopt certain
+standards published by the North American Energy Standards Board with respect to
+shipper creditworthiness. The standards are intended to facilitate and increase
+transparency in the creditworthiness evaluation process.
+The FERC is presently reviewing in Docket No. PL04-3 whether it should adopt
+standards for "interchangeability" of natural gas, that is, whether it should
+standardize the composition and quality of natural gas transported through the
+delivery system, including interstate pipelines. Although the standards, if any,
+are likely to be voluntary, at the present time the approach that the FERC will
+take and the potential impact on gas supply are not clear.
+With respect to the transportation of natural gas on or across the Outer
+Continental Shelf ("OCS"), the FERC requires, as part of its regulation under
+the Outer Continental Shelf Lands Act ("OCSLA"), that all pipelines provide open
+and non-discriminatory access to both owner and non-owner shippers. Although to
+date the FERC has imposed light-handed regulation on off-shore facilities that
+meet its traditional test of gathering status, it has the authority to exercise
+jurisdiction under the OCSLA over gathering facilities, if necessary, to permit
+non-discriminatory access to service. In an effort to heighten its oversight of
+the OCS, the FERC recently attempted to promulgate reporting requirements for
+all OCS "service providers," including gatherers, but the regulations were
+struck down as ultra vires by a federal district court in October, 2003. In
+addition, the FERC recently reasserted NGA jurisdiction over certain offshore
+gathering facilities over which it had previously disclaimed jurisdiction where
+it determined that the FERC's open access regulatory regime was being frustrated
+by an interstate pipeline in concert with an affiliated gathering company. For
+those facilities transporting natural gas across the OCS that are not considered
+to be gathering facilities, the rates, terms, and conditions applicable to this
+transportation are regulated by the FERC under the NGA and NGPA, as well as the
+OCSLA.
+SALES AND TRANSPORTATION OF CRUDE OIL. Sales of crude oil and condensate can be
+made by us at market prices not subject at this time to price controls. The
+price that we receive from the sale of these products will be affected by the
+cost of transporting the products to market. The rates, terms, and conditions
+applicable to the interstate transportation of oil and related products by
+pipelines are regulated by the FERC under the Interstate Commerce Act. Pursuant
+to the Energy Policy Act of 1992, which "grandfathered" certain existing rates,
+the FERC presently regulates oil pipeline rates under a light-handed,
+streamlined regulatory regime where rates are adjusted annually using an index
+ceiling based upon the producer price index. The FERC recently modified the
+formula for calculating the index such that the index ceilings are now set
+slightly higher than in their original iteration. As an exception to indexing,
+the FERC will also, under defined circumstances, permit alternative ratemaking
+methodologies for interstate oil pipelines such as the use of cost of service
+rates, settlement rates, and market-based rates. Market-based rates will be
+permitted to the extent the pipeline can demonstrate that it lacks significant
+market power in the market in which it proposes to charge market-based rates.
+The cumulative effect that these rules have had on moving our production to
+market have not been material.
+With respect to the transportation of oil and condensate on or across the OCS,
+the FERC requires, as part of its regulation under the OCSLA, that all pipelines
+provide open and non-discriminatory access to both owner and non-owner shippers.
+Accordingly, the FERC has the authority to exercise jurisdiction under the
+OCSLA, if necessary, to permit non-discriminatory access to service.
+13
+LEGISLATIVE PROPOSALS. In the past, Congress has been very active in the area of
+natural gas regulation. There are legislative proposals pending in Congress and
+in various state legislatures which, if enacted, could significantly affect the
+petroleum industry. At the present time it is difficult to predict what
+proposals, if any, might actually be enacted by Congress or the various state
+legislatures and what effect, if any, such proposals might have on our
+operations.
+FEDERAL, STATE OR INDIAN LEASES. In the event we conduct operations on federal,
+state or Indian oil and gas leases, such operations must comply with numerous
+regulatory restrictions, including various nondiscrimination statutes, royalty
+and related valuation requirements, and certain of such operations must be
+conducted pursuant to on-site security regulations and other appropriate permits
+issued by the Bureau of Land Management ("BLM") or Minerals Management Service
+("MMS") or other appropriate federal or state agencies.
+The Company's OCS leases in federal waters are administered by the MMS and
+require compliance with detailed MMS regulations and orders. The MMS has
+promulgated regulations implementing restrictions on various production-related
+activities, including restricting the flaring or venting of natural gas. Under
+certain circumstances, the MMS may require our operations on federal leases to
+be suspended or terminated. Any such suspension or termination could materially
+and adversely affect our financial condition and operations. On March 15, 2000,
+the MMS issued a final rule effective June 1, 2000 which amends its regulations
+governing the calculation of royalties and the valuation of crude oil produced
+from federal leases. Among other matters, this rule amends the valuation
+procedure for the sale of federal royalty oil by eliminating posted prices as a
+measure of value and relying instead on arm's length sales prices and spot
+market prices as market value indicators. Because we sell our production in the
+spot market and therefore pay royalties on production from federal leases, it is
+not anticipated that this final rule will have any substantial impact on us.
+The Mineral Leasing Act of 1920 ("Mineral Act") prohibits direct or indirect
+ownership of any interest in federal onshore oil and gas leases by a foreign
+citizen of a country that denies "similar or like privileges" to citizens of the
+United States. Such restrictions on citizens of a "non-reciprocal" country
+include ownership or holding or controlling stock in a corporation that holds a
+federal onshore oil and gas lease. If this restriction is violated, the
+corporation's lease can be canceled in a proceeding instituted by the United
+States Attorney General. Although the regulations of the BLM (which administers
+the Mineral Act) provide for agency designations of non-reciprocal countries,
+there are presently no such designations in effect. We own interests in numerous
+federal onshore oil and gas leases. It is possible that some of our stockholders
+may be citizens of foreign countries, which at some time in the future might be
+determined to be non-reciprocal under the Mineral Act.
+STATE REGULATIONS
+Most states regulate the production and sale of oil and natural gas, including
+requirements for obtaining drilling permits, the method of developing new
+fields, the spacing and operation of wells and the prevention of waste of oil
+and gas resources. The rate of production may be regulated and the maximum daily
+production allowable from both oil and gas wells may be established on a market
+demand or conservation basis or both.
+We may enter into agreements relating to the construction or operation of a
+pipeline system for the transportation of natural gas. To the extent that such
+gas is produced, transported and consumed wholly within one state, such
+operations may, in certain instances, be subject to the jurisdiction of such
+state's administrative authority charged with the responsibility of regulating
+intrastate pipelines. In such event, the
+14
+rates which we could charge for gas, the transportation of gas, and the costs of
+construction and operation of such pipeline would be impacted by the rules and
+regulations governing such matters, if any, of such administrative authority.
+Further, such a pipeline system would be subject to various state and/or federal
+pipeline safety regulations and requirements, including those of, among others,
+the Department of Transportation. Such regulations can increase the cost of
+planning, designing, installing and operating such facilities. The impact of
+such pipeline safety regulations would not be any more adverse to us than it
+would be to other similar owners or operators of such pipeline facilities.
+ENVIRONMENTAL REGULATIONS
+GENERAL. Our activities are subject to federal, state and local laws and
+regulations governing environmental quality and pollution control. Although no
+assurances can be made, we believe that, absent the occurrence of an
+extraordinary event, compliance with existing federal, state and local laws,
+rules and regulations regulating the release of materials into the environment
+or otherwise relating to the protection of the environment will not have a
+material effect upon our capital expenditures, earnings or competitive position
+with respect to our existing assets and operations. We cannot predict what
+effect future regulation or legislation, enforcement policies, and claims for
+damages to property, employees, other persons and the environment resulting from
+our operations could have on our activities.
+Our activities with respect to natural gas facilities, including the operation
+and construction of pipelines, plants and other facilities for transporting,
+processing, treating or storing natural gas and other products, are subject to
+stringent environmental regulation by state and federal authorities including
+the United States Environmental Protection Agency ("EPA"). Such regulation can
+increase the cost of planning, designing, installing and operating such
+facilities. In most instances, the regulatory requirements relate to water and
+air pollution control measures. Although we believe that compliance with
+environmental regulations will not have a material adverse effect on us, risks
+of substantial costs and liabilities are inherent in oil and gas production
+operations, and there can be no assurance that significant costs and liabilities
+will not be incurred. Moreover, it is possible that other developments, such as
+stricter environmental laws and regulations, and claims for damages to property
+or persons resulting from oil and gas production, would result in substantial
+costs and liabilities to us.
+SOLID AND HAZARDOUS WASTE. We currently own or lease, and in the past owned or
+leased, properties that have been used for the exploration and production of oil
+and gas for many years. Although we have utilized operating and disposal
+practices that were standard in the industry at the time, hydrocarbons or other
+solid wastes may have been disposed or released on or under the properties owned
+or leased by us or on or under locations where such wastes have been taken for
+disposal. In addition, many of these properties have been operated by third
+parties. We have no control over such entities' treatment of hydrocarbons or
+other solid wastes and the manner in which such substances may have been
+disposed or released. State and federal laws applicable to oil and gas wastes
+and properties have gradually become stricter over time. Under new laws, we
+could be required to remediate property, including groundwater, containing or
+impacted by previously disposed wastes (including wastes disposed or released by
+prior owners or operators, or property contamination, including groundwater
+contamination by prior owners or operators) or to perform remedial plugging
+operations to prevent future or mitigate existing contamination.
+We generate wastes, including hazardous wastes that are subject to the federal
+Resource Conservation and Recovery Act ("RCRA") and comparable state statutes.
+The EPA and various state agencies have limited the disposal options for certain
+wastes, including wastes designated as hazardous under the RCRA and similar
+state statutes ("Hazardous Wastes"). Furthermore, it is possible that certain
+wastes generated by our oil and gas operations that are (currently exempt from
+treatment as) Hazardous Wastes may in the future be
+15
+designated as Hazardous Wastes under RCRA or other applicable statutes and,
+therefore, may be subject to more rigorous and costly disposal requirements.
+SUPERFUND. The federal Comprehensive Environmental Response, Compensation and
+Liability Act ("CERCLA"), also known as the "Superfund" law, generally imposes
+joint and several liability for costs of investigation and remediation and for
+natural resource damages, without regard to fault or the legality of the
+original conduct, on certain classes of persons with respect to the release into
+the environment of substances designated under CERCLA as hazardous substances
+("Hazardous Substances"). These classes of persons, or so-called potentially
+responsible parties ("PRPs"), include the current and certain past owners and
+operators of a facility where there has been a release or threat of release of a
+Hazardous Substance and persons who disposed of or arranged for the disposal of
+Hazardous Substances found at a site. CERCLA also authorizes the EPA and, in
+some cases, third parties to take actions in response to threats to the public
+health or the environment and to seek to recover from the PRPs the costs of such
+action. Although CERCLA generally exempts "petroleum" from the definition of
+Hazardous Substance, in the course of its operations, we have generated and will
+generate wastes that may fall within CERCLA's definition of Hazardous Substance.
+We may also be the owner or operator of sites on which Hazardous Substances have
+been released. To our knowledge, neither we nor our predecessors have been
+designated as a PRP by the EPA under CERCLA. We also do not know of any prior
+owners or operators of our properties that are named as PRPs related to their
+ownership or operation of such properties.
+CLEAN WATER ACT. The Clean Water Act ("CWA") imposes restrictions and strict
+controls regarding the discharge of wastes including produced waters and other
+oil and natural gas wastes, into waters of the United States, a term broadly
+defined. These controls have become more stringent over the years, and it is
+probable that additional restrictions will be imposed in the future. Permits
+must be obtained to discharge pollutants into federal waters. The CWA provides
+for civil, criminal and administrative penalties for unauthorized discharges of
+oil and hazardous substances and of other pollutants. It imposes substantial
+potential liability for the costs of removal or remediation associated with
+discharges of oil or hazardous substances and other pollutants. State laws
+governing discharges to water also provide varying civil, criminal and
+administrative penalties and impose liabilities in the case of a discharge of
+petroleum or its derivatives, or other hazardous substances, into state waters.
+In addition, the EPA has promulgated regulations that may require us to obtain
+permits to discharge storm water runoff, including discharges associated with
+construction activities. In the event of an unauthorized discharge of wastes, we
+may be liable for penalties and costs.
+OIL POLLUTION ACT. The Oil Pollution Act of 1990 ("OPA"), which amends and
+augments oil spill provisions of the CWA, imposes certain duties and liabilities
+on certain "responsible parties" related to the prevention of oil spills and
+damages resulting from such spills in or threatening United States waters or
+adjoining shorelines. A liable "responsible party" includes the owner or
+operator of a facility, vessel or pipeline that is a source of an oil discharge
+or that poses the substantial threat of discharge, or the lessee or permittee of
+the area in which a discharging facility is located. The OPA assigns joint and
+several liability, without regard to fault, to each liable party for oil removal
+costs and a variety of public and private damages. Although defenses and
+limitations exist to the liability imposed by OPA, they are limited. In the
+event of an oil discharge or substantial threat of discharge, we may be liable
+for costs and damages.
+The OPA also imposes ongoing requirements on a responsible party, including
+proof of financial responsibility to cover at least some costs in a potential
+spill. Certain amendments to the OPA that were enacted in 1996 require owners
+and operators of offshore facilities that have a worst case oil spill potential
+of more than 1,000 barrels to demonstrate financial responsibility in amounts
+ranging from $10 million in specified state waters and $35 million in federal
+OCS waters, with higher amounts, up to $150 million based
+16
+upon worst case oil-spill discharge volume calculations. We believe that we have
+established adequate proof of financial responsibility for our offshore
+facilities.
+AIR EMISSIONS. Our operations are subject to local, state and federal
+regulations for the control of emissions from sources of air pollution. Federal
+and state laws require new and modified sources of air pollutants to obtain
+permits prior to commencing construction. Major sources of air pollutants are
+subject to more stringent, federally imposed requirements including additional
+permits. Federal and state laws designed to control hazardous (toxic) air
+pollutants, might require installation of additional controls. Administrative
+enforcement actions for failure to comply strictly with air pollution
+regulations or permits are generally resolved by payment of monetary fines and
+correction of any identified deficiencies. Alternatively, regulatory agencies
+could bring lawsuits for civil penalties or require us to forego construction,
+modification or operation of certain air emission sources.
+COASTAL COORDINATION. There are various federal and state programs that regulate
+the conservation and development of coastal resources. The federal Coastal Zone
+Management Act ("CZMA") was passed in 1972 to preserve and, where possible,
+restore the natural resources of the Nation's coastal zone. The CZMA provides
+for federal grants for state management programs that regulate land use, water
+use and coastal development.
+Various states, such as Alabama, Louisiana and Texas, also have coastal
+management programs, which provide for, among other things, the coordination
+among local and state authorities to protect coastal resources through
+regulating land use, water, and coastal development. Coastal management programs
+also may provide for the review of state and federal agency rules and agency
+actions for consistency with the goals and policies of the state coastal
+management plan. This review may impact agency permitting and review activities
+and add an additional layer of review to certain activities undertaken by us.
+OSHA AND OTHER REGULATIONS. We are subject to the requirements of the federal
+Occupational Safety and Health Act ("OSHA") and comparable state statutes. The
+OSHA hazard communication standard, the EPA community right-to-know regulations
+under Title III of CERCLA and similar state statutes require us to organize
+and/or disclose information about hazardous materials used or produced in its
+operations.
+Our management believes that we are in substantial compliance with current
+applicable environmental laws and regulations and that continued compliance with
+existing requirements would not have a material adverse impact on us.
+PROPERTY SUMMARY
+We are engaged in the exploration, development, acquisition and production of
+oil and gas properties and provide oil and gas property management services for
+other investors. Our properties are concentrated offshore in the Gulf of Mexico
+and onshore, primarily, in Louisiana and Alabama. We have historically grown our
+reserves and production by focusing primarily on low to moderate risk
+exploration and acquisition opportunities in the Gulf of Mexico shelf area. Over
+the last several years, we have expanded our area of exploration to include the
+Gulf of Mexico deepwater area. As of December 31, 2003, our estimated net proved
+reserves totaled 23.7 million barrels of oil ("MBbl") and 74.7 billion cubic
+feet of natural gas ("Bcf"), with a pre-tax present value, discounted at 10%, of
+the estimated future net revenues based on constant prices in effect at year-end
+("Discounted Cash Flow") of $570.5 million. Gas constitutes approximately 34% of
+our total estimated proved reserves and approximately 42% of our total estimated
+proved reserves are proved developed reserves.
+17
+Our Medusa (Mississippi Canyon Blocks 538/582) and Habanero (Garden Banks Block
+341) discoveries began production in the fourth quarter of 2003. These two
+deepwater discoveries are expected to increase our projected 2004 production by
+approximately 85% from 2003 levels. A detail discussion of each of these
+properties is provided in the "Significant Properties" section of this report.
+SIGNIFICANT PROPERTIES
+The following table shows discounted cash flows and estimated net proved oil and
+gas reserves by major field, within the focus area, for our seven largest fields
+and for all other properties combined at December 31, 2003.
+ESTIMATED NET PROVED RESERVES PRE-TAX
+------------------------------ DISCOUNTED
+OIL GAS TOTAL PRESENT VALUE
+OPERATOR (MBBLS) (MMCF) (MMCFE) ($000)
+-------- -------- -------- -------- -------------
+(A)(B)
+GULF OF MEXICO DEEPWATER:
+Mississippi Canyon Blocks 538/582
+"Medusa" Murphy 10,312 6,173 68,043 $160,297
+Garden Banks Block 341
+"Habanero" Shell 4,687 11,207 39,328 124,876
+Garden Banks Blocks 738/782/826/827
+"Entrada" BP Amoco 7,772 29,126 75,760 185,608
+GULF OF MEXICO SHELF:
+Mobile Blocks 863/864/907/908 Callon -- 4,873 4,873 15,641
+Mobile Blocks 952/953/955 Callon -- 15,229 15,229 60,487
+Ship Shoal Blocks 28/35 Callon 6 701 739 3,115
+ONSHORE AND OTHER:
+Big Escambia Creek Exxon 422 1,188 3,718 6,116
+Other Various 510 6,194 9,253 14,323
+-------- -------- -------- --------
+TOTAL NET PROVED RESERVES 23,709 74,691 216,943 $570,463
+======== ======== ======== ========
+(a) Represents the present value of future net cash flows before deduction of
+federal income taxes, discounted at 10%, attributable to estimated net
+proved reserves as of December 31, 2003, as set forth in the Company's
+reserve reports prepared by its independent petroleum reserve engineers,
+Huddleston & Co., Inc. of Houston, Texas.
+(b) Includes a reduction for estimated plugging and abandonment costs that is
+reflected as a liability on our balance sheet at December 31, 2003, in
+accordance with Statement of Financial Accounting Standards No. 143.
+18
+GULF OF MEXICO DEEPWATER
+Medusa, Mississippi Canyon Blocks 538/582
+Our Medusa deepwater discovery was announced in September 1999, when we drilled
+the initial test well in 2,235 feet of water to a total depth of 16,241 feet and
+encountered over 120 feet of pay in two intervals. Subsequent sidetrack drilling
+from the wellbore was used to determine the extent of the discovery and a second
+successful well was drilled in the first quarter of 2000 to further delineate
+the extent of the pay intervals. We own a 15% working interest, Murphy, the
+operator, owns a 60% working interest and Agip Ventures, formerly British-Borneo
+Petroleum, Inc., owns the remaining 25% working interest.
+In 2001 a drilling program began which included four development wells and one
+sidetrack. The program included production casing being set on six wells to
+provide initial production take-points. The program was completed in the first
+half of 2002. Also in 2001, the operator submitted an Authorization for
+Expenditure for a floating production system, spar, at Medusa and awarded the
+contract to J. Ray McDermott, Inc. The spar hull was barged to Mississippi
+Canyon Block 582 during the first quarter of 2003, uprighted, moored and placed
+in position to receive the production deck. The topside deck and production
+facilities were delivered and lifted into place atop the spar hull during the
+second quarter of 2003. The A-1 well, the first of six, was completed and tied
+into the spar and commenced production in late November 2003. The A-2 well
+commenced production in January 2004 and during February 2004 the field produced
+approximately 19,000 barrels of oil and 18 million cubic feet of gas per day.
+Initial production from the A-3 well is expected during March 2004 and will be
+followed by initial production from the A-6 and A-4 wells in the second quarter
+of 2004 with production from the A-5 well expected early in the 3rd quarter of
+2004. Peak production from the field is expected to reach approximately 40,000
+barrels of crude oil and 35 million cubic feet of natural gas per day.
+In December 2003, we transferred our undivided 15% working interest in the spar
+production facilities to Medusa Spar LLC in exchange for cash proceeds of
+approximately $25 million and a 10% ownership interest in the LLC. A detailed
+discussion of this transaction is included in Management's Discussion and
+Analysis of Financial Condition and Results of Operations-"Off-Balance Sheet
+Arrangements".
+Habanero, Garden Banks Block 341
+During February 1999 the initial test well on our Habanero deepwater discovery
+encountered over 200 feet of net pay in two zones. Located in 2,000 feet of
+water, the well was drilled to a measured depth of 21,158 feet. We own an 11.25%
+working interest in the well. The well is operated by Shell Deepwater
+Development Inc., which owns a 55% working interest, with the remaining working
+interest being owned by Murphy.
+A field delineation program began in mid-year 2001, which included three
+sidetracks of the discovery well. Production casing was set on this well through
+one of the sidetracks to the Habanero 52 oil and gas sand and the Habanero 55
+gas sand. Initial production will be from the Habanero 55 gas sand and future
+recompletions are scheduled up-hole to the Habanero 52 oil and gas sand. Also, a
+development well was drilled in the summer of 2003 which provides a take-point
+for production from the Habanero 52 oil sand.
+19
+By means of a sub-sea completion and tie back to an existing production facility
+in the area operated by Shell, production from the Habanero 52 oil sand
+commenced in late November 2003. Production from the Habanero 55 gas sand
+commenced in January, after mechanical adjustments were made down hole. Gross
+production during February 2003 from the Habanero field was approximately 22,000
+barrels of oil and 56 million cubic feet of gas per day.
+Entrada, Garden Banks Blocks 738/782/826/827
+The Entrada discovery is located in approximately 4,500 feet of water in the
+Gulf of Mexico. Two wells and seven sidetracks have been drilled to date on
+Garden Banks 782 on a northwest plunging salt ridge along the southern edge of
+the Entrada Basin. Multiple stacked amplitudes trapped against a salt or fault
+interface characterize the Entrada Area. We own a 20% working interest in this
+discovery with BP Amoco, the operator, holding the remaining working interest.
+The owners of an adjacent discovery have announced their plans to construct
+production facilities to enable them to be a regional off-take point in
+Southeastern Garden Banks. These plans include handling third party tie-ins. We
+expect to tie-in Entrada to this regional off-take point with initial production
+anticipated in 2006. First production from the adjacent discovery is expected in
+late 2004. Information obtained in a data swap with the adjacent owners is being
+incorporated into the Entrada development plans. An integrated project team was
+formed by the working interest owners during 2002 to begin planning the
+development of the field. The team has been reviewing alternate development
+plans which could accelerate field development.
+GULF OF MEXICO SHELF
+Mobile Blocks 863/864/ 907/908
+We own an average 67.9% working interest in these blocks and we are the
+operator. The Mobile 864 unit, in which we have a 66.4% working interest, has
+three producing wells, unit production facilities and covers portions of these
+four blocks. During 2003 the unit produced an average of 4.9 MMcf per day net to
+us.
+Mobile Blocks 952/953/955
+We own a 100% working interest in these three blocks and we are the operator. In
+the fourth quarter of 2001, we initiated a production acceleration program for
+Mobile Blocks 952, 953 and 955, which were being produced through the Mobile
+Block 864 unit facilities. An acceleration well was successfully drilled in the
+fourth quarter of 2001 and stand-alone production facilities were installed and
+production flow lines were rerouted to the new facilities. Production commenced
+through the new facilities in April 2002. In order to completely produce the
+proved reserves of the field we drilled a development well on Mobile Block 955
+during the first quarter of 2004. The well is flowing without compression and
+commenced production in March 2004 at a gross rate of approximately 8 MMcf per
+day. The installation of compression facilities at the well site is expected to
+be completed by June 2004 and should increase the production rate by an
+additional 2-3 MMcf per day. Production from the field for 2003 was 19.6 MMcf
+per day net to us. Production for 2002 was 14.0 MMcf per day net to us.
+20
+Ship Shoal Blocks 28/35
+We successfully drilled an exploratory well at Ship Shoal Blocks 28 and 35
+during the third quarter of 2002. The well was drilled to a measured depth of
+15,237 feet (12,295 feet of true vertical depth) and encountered 140 feet of net
+natural gas pay. The well was completed as a single producer in the deepest of
+three productive intervals and first production commenced in late April, 2003
+and averaged 1.7 MMcfe per day net to us through December 31, 2003. We operate
+and own a 22% working interest.
+ONSHORE AND OTHER
+Big Escambia Creek
+This gas field in south Alabama produces from the Smackover formation at depths
+ranging from 15,100 to 15,600 feet and is operated by ExxonMobil. We own an
+average working interest of 4.9% (5.5% net revenue interest), in six wells and a
+2.2% average royalty interest in another five wells. This field produced 0.7
+MMcfe per day to our interest in 2003. The field has an estimated reserve life
+in excess of 10 years given current production rates.
+Other
+We own various royalty and working interests in numerous onshore areas and the
+Gulf of Mexico other than the fields discussed above.
+21
+OIL AND GAS RESERVES
+The following table sets forth certain information about our estimated proved
+reserves as of the dates set forth below.
+YEARS ENDED DECEMBER 31,
+---------------------------------
+2003 2002(a) 2001(a)
+--------- --------- ---------
+(IN THOUSANDS)
+Proved developed:
+Oil (Bbls) 9,919 1,056 885
+Gas (Mcf) 31,415 37,631 52,375
+Mcfe 90,926 43,966 57,683
+Proved undeveloped:
+Oil (Bbls) 13,790 22,988 29,324
+Gas (Mcf) 43,276 53,908 69,078
+Mcfe 126,017 191,833 245,023
+Total proved:
+Oil (Bbls) 23,709 24,043 30,209
+Gas (Mcf) 74,691 91,539 121,453
+Mcfe 216,943 235,799 302,706
+Estimated pre-tax future net cash flows(b) $ 838,847 $ 970,198 $ 473,896
+========= ========= =========
+Pre-tax discounted present value (b) $ 570,463 $ 623,946 $ 272,053
+========= ========= =========
+Standardized measure of discounted future
+net cash flows(b) $ 519,026 $ 556,046 $ 254,857
+========= ========= =========
+(a) The estimates include reserve volumes of approximately 1.2 Bcf, $2.9
+million of pre-tax discounted present value in 2001, attributable to
+a volumetric production payment. Standardized measure of discounted
+future net cash flows does not include any volumes or cash flows
+associated with the volumetric production payment.
+(b) Includes a reduction for estimated plugging and abandonment costs
+that is reflected as a liability on our balance sheet at December
+31, 2003, in accordance with Statement of Financial Accounting
+Standards No. 143.
+Our independent reserve engineers, Huddleston & Co., Inc., prepared the
+estimates of the proved reserves and the future net cash flows and present value
+thereof attributable to such proved reserves. Reserves were estimated using oil
+and gas prices and production and development costs in effect on December 31 of
+each such year, without escalation, and were otherwise prepared in accordance
+with Securities and Exchange Commission regulations regarding disclosure of oil
+and gas reserve information.
+There are numerous uncertainties inherent in estimating quantities of proved
+reserves, including many factors beyond our control or the control of the
+reserve engineers. Reserve engineering is a subjective
+22
+process of estimating underground accumulations of oil and gas that cannot be
+measured in an exact manner. The accuracy of any reserve or cash flow estimate
+is a function of the quality of available data and of engineering and geological
+interpretation and judgment. Estimates by different engineers often vary,
+sometimes significantly. In addition, physical factors, such as the results of
+drilling, testing and production subsequent to the date of an estimate, as well
+as economic factors, such as an increase or decrease in product prices that
+renders production of such reserves more or less economic, may justify revision
+of such estimates. Accordingly, reserve estimates could be different from the
+quantities of oil and gas that are ultimately recovered.
+We have not filed any reports with other federal agencies which contain an
+estimate of total proved net oil and gas reserves during our last fiscal year.
+PRESENT ACTIVITIES AND PRODUCTIVE WELLS
+The following table sets forth the wells we have drilled and completed during
+the periods indicated. All such wells were drilled in the continental United
+States primarily in federal and state waters in the Gulf of Mexico.
+YEARS ENDED DECEMBER 31,
+---------------------------------------------
+2003 2002 2001
+------------- ------------- -------------
+GROSS NET GROSS NET GROSS NET
+----- ----- ----- ----- ----- -----
+Development:
+Oil 2 .23 2 .30 6 .45
+Gas -- -- -- -- 4 3.17
+Non-productive -- -- 1 .40 -- --
+----- ----- ----- ----- ----- -----
+Total 2 .23 3 .70 10 3.62
+===== ===== ===== ===== ===== =====
+Exploration:
+Oil 1 .15 -- -- -- --
+Gas -- -- 1 .22 3 2.00
+Non-productive 1 .20 1 .50 12 5.77
+----- ----- ----- ----- ----- -----
+Total 2 .35 2 .72 15 7.77
+===== ===== ===== ===== ===== =====
+The following table sets forth our productive wells as of December 31, 2003:
+WELLS
+--------------
+GROSS NET
+------ -----
+Oil:
+Working interest 39.00 3.05
+Royalty interest 188.00 3.20
+------ ----
+Total 227.00 6.25
+====== ====
+Gas:
+Working interest 41.00 21.11
+Royalty interest 209.00 1.67
+------ ----
+Total 250.00 22.78
+====== =====
+23
+A well is categorized as an oil well or a natural gas well based upon the ratio
+of oil to gas reserves on a Mcfe basis. However, some of our wells produce both
+oil and gas. At December 31, 2003, we had no wells with multiple completions. At
+December 31, 2003, we had 1 gross (0.03 net) exploratory oil well in progress.
+LEASEHOLD ACREAGE
+The following table shows our approximate developed and undeveloped (gross and
+net) leasehold acreage as of December 31, 2003.
+LEASEHOLD ACREAGE
+-----------------------------------
+DEVELOPED UNDEVELOPED
+---------------- ----------------
+LOCATION GROSS NET GROSS NET
+-------------- ------- ------ ------- ------
+Louisiana 6,554 4,179 3,770 1,179
+Other states 680 362 681 509
+Federal waters 101,743 73,483 295,180 77,207
+------- ------ ------- ------
+Total 108,977 78,024 299,631 78,895
+======= ====== ======= ======
+As of December 31, 2003, we owned various royalty and overriding royalty
+interests in 1,336 net developed and 6,862 net undeveloped acres. In addition,
+we owned 4,711 developed and 121,289 undeveloped mineral acres.
+MAJOR CUSTOMERS
+Our production is sold generally on month-to-month contracts at prevailing
+prices. The following table identifies customers to whom we sold a significant
+percentage of our total oil and gas production during each of the 12-month
+periods ended:
+DECEMBER 31,
+----------------------
+2003 2002 2001
+---- ---- ----
+Petrocom Energy Group, Ltd. 4% 4% --
+Dynegy 5% 7% 8%
+Prior Energy Corporation 20% -- 20%
+Reliant Energy Services 28% 70% 49%
+Louis Dreyfus Energy Services 27% -- --
+Because alternative purchasers of oil and gas are readily available, we believe
+that the loss of any of these purchasers would not result in a material adverse
+effect on our ability to market future oil and gas production.
+TITLE TO PROPERTIES
+We believe that the title to our oil and gas properties is good and defensible
+in accordance with standards generally accepted in the oil and gas industry,
+subject to such exceptions which, in our opinion, are not so
+24
+material as to detract substantially from the use or value of such properties.
+Our properties are typically subject, in one degree or another, to one or more
+of the following:
+- royalties and other burdens and obligations, express or implied,
+under oil and gas leases;
+- overriding royalties and other burdens created by us or our
+predecessors in title;
+- a variety of contractual obligations (including, in some cases,
+development obligations) arising under operating agreements, farmout
+agreements, production sales contracts and other agreements that may
+affect the properties or their titles;
+- back-ins and reversionary interests existing under purchase
+agreements and leasehold assignments;
+- liens that arise in the normal course of operations, such as those
+for unpaid taxes, statutory liens securing obligations to unpaid
+suppliers and contractors and contractual liens under operating
+agreements;
+- pooling, unitization and communitization agreements, declarations
+and orders; and easements, restrictions, rights-of-way and other
+matters that commonly affect property.
+To the extent that such burdens and obligations affect our rights to production
+revenues, they have been taken into account in calculating our net revenue
+interests and in estimating the size and value of our reserves. We believe that
+the burdens and obligations affecting our properties are conventional in the
+industry for properties of the kind owned by us.
+ITEM 3. LEGAL PROCEEDINGS
+We are a defendant in various legal proceedings and claims, which arise in the
+ordinary course of our business. We do not believe the ultimate resolution of
+any such actions will have a material affect on our financial position or
+results of operations.
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
+There were no matters submitted to a vote of security holders during the fourth
+quarter of 2003.
+25
+PART II.
+ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
+Our common stock trades on the New York Stock Exchange under the symbol "CPE".
+The following table sets forth the high and low sale prices per share as
+reported for the periods indicated.
+QUARTER ENDED HIGH LOW
+-------------- ------ ------
+2002:
+First quarter $ 9.40 $ 3.97
+Second quarter 8.39 4.50
+Third quarter 5.15 3.20
+Fourth quarter 6.25 3.35
+2003:
+First quarter $ 4.35 $ 3.35
+Second quarter 8.44 3.66
+Third quarter 7.95 5.46
+Fourth quarter 11.48 7.31
+As of March 4, 2004, there were approximately 4,514 common stockholders of
+record.
+We have never paid dividends on our common stock and intend to retain our cash
+flow from operations, net of preferred stock dividends, for the future operation
+and development of our business. In addition, our primary credit facility and
+the terms of our outstanding subordinated debt prohibit the payment of cash
+dividends on our common stock.
+In December 2003, we borrowed $185 million pursuant to an amended and restated
+senior unsecured credit agreement dated December 23, 2003. In connection with
+our borrowings under the senior unsecured credit agreement, we issued to the
+lenders under the credit agreement warrants to purchase an aggregate of
+2,775,000 shares of our common stock at an exercise price of $10.00 per share.
+The warrants are exercisable for seven years from the date of issuance. The
+issuance of the warrants was exempt pursuant to Section 4(2) of the Securities
+Act of 1933.
+ITEM 6. SELECTED FINANCIAL DATA
+The following table sets forth, as of the dates and for the periods indicated,
+selected financial information about us. The financial information for each of
+the five years in the period ended December 31, 2003 has been derived from our
+audited Consolidated Financial Statements for such periods. The information
+should be read in conjunction with "Management's Discussion and Analysis of
+Financial Condition and Results of Operations" and the Consolidated Financial
+Statements and Notes thereto. The following information is not necessarily
+indicative of our future results.
+26
+CALLON PETROLEUM COMPANY
+SELECTED HISTORICAL FINANCIAL INFORMATION
+(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
+YEARS ENDED DECEMBER 31,
+--------------------------------------------------------------
+2003 2002 2001 2000 1999
+---------- ---------- ---------- ---------- ----------
+STATEMENT OF OPERATIONS DATA:
+Operating revenues:
+Oil and gas sales $ 73,697 $ 61,171 $ 60,010 $ 56,310 $ 37,140
+---------- ---------- ---------- ---------- ----------
+Operating expenses:
+Lease operating expenses 11,301 11,030 11,252 9,339 7,536
+Depreciation, depletion and amortization 28,253 27,096 21,081 17,153 16,727
+General and administrative 4,713 4,705 4,635 4,155 4,575
+Accretion expense 2,884 -- -- -- --
+Loss on mark-to-market commodity derivative contracts 535 708 -- -- --
+---------- ---------- ---------- ---------- ----------
+Total operating expenses 47,686 43,539 36,968 30,647 28,838
+---------- ---------- ---------- ---------- ----------
+Income (loss) from operations 26,011 17,632 23,042 25,663 8,302
+---------- ---------- ---------- ---------- ----------
+Other (income) expenses:
+Interest expense 30,614 26,140 12,805 8,420 6,175
+Other income (444) (1,004) (1,742) (1,767) (1,853)
+Loss on early extinguishment of debt 5,573 -- -- --
+Gain on sale of pipeline -- (2,454) -- -- --
+Gain on sale of Enron derivatives -- (2,479) -- -- --
+Writedown of Enron derivatives -- -- 9,186 -- --
+---------- ---------- ---------- ---------- ----------
+Total other (income) expenses 35,743 20,203 20,249 6,653 4,322
+---------- ---------- ---------- ---------- ----------
+Net income (loss) before income taxes (9,732) (2,571) 2,793 19,010 3,980
+Income tax expense (benefit) 8,432 (900) 977 6,463 1,353
+---------- ---------- ---------- ---------- ----------
+Net income (loss) before Medusa Spar LLC and
+cumulative effect of change in accounting principle (18,164) (1,671) 1,816 12,547 2,627
+Loss on Medusa Spar LLC, net of tax (8) -- -- -- --
+---------- ---------- ---------- ---------- ----------
+Net income (loss) before cumulative effect of change in
+in accounting principle (18,172) (1,671) 1,816 12,547 2,627
+Cumulative effect of change in accounting principle,
+net of tax 181 -- -- -- --
+---------- ---------- ---------- ---------- ----------
+Net income (loss) (17,991) (1,671) 1,816 12,547 2,627
+Preferred stock dividends 1,277 1,277 1,277 2,403 2,497
+---------- ---------- ---------- ---------- ----------
+Net income (loss) available to common shares $ (19,268) $ (2,948) $ 539 $ 10,144 $ 130
+========== ========== ========== ========== ==========
+27
+CALLON PETROLEUM COMPANY
+SELECTED HISTORICAL FINANCIAL INFORMATION
+(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
+YEARS ENDED DECEMBER 31,
+----------------------------------------------------
+2003 2002 2001 2000 1999
+-------- -------- -------- -------- --------
+Net income (loss) available to common shares $(19,268) $ (2,948) $ 539 $ 10,144 $ 130
+======== ======== ======== ======== ========
+Net income (loss) per common share:
+Basic:
+Net income (loss) available to common before cumulative
+effect of change in accounting principle $ (1.42) $ (.22) $ .04 $ .82 $ .01
+Cumulative effect of change in accounting principle,
+net of tax .01 -- -- -- --
+-------- -------- -------- -------- --------
+Net income (loss) available to common $ (1.41) $ (.22) $ .04 $ .82 $ .01
+======== ======== ======== ======== ========
+Diluted:
+Net income (loss) available to common before cumulative
+effect of change in accounting principle $ (1.42) $ (.22) $ .04 $ .80 $ .01
+Cumulative effect of change in accounting principle,
+net of tax .01 -- -- -- --
+-------- -------- -------- -------- --------
+Net income (loss) available to common $ (1.41) $ (.22) $ .04 $ .80 $ .01
+======== ======== ======== ======== ========
+Shares used in computing net income (loss) per common share:
+Basic 13,662 13,387 13,273 12,420 8,976
+======== ======== ======== ======== ========
+Diluted 13,662 13,387 13,366 12,745 9,075
+======== ======== ======== ======== ========
+BALANCE SHEET DATA (END OF PERIOD):
+Oil and gas properties, net $390,163 $377,661 $343,158 $258,613 $194,365
+Total assets $496,032 $410,613 $372,095 $301,569 $259,877
+Long-term debt, less current portion $214,885 $248,269 $161,733 $134,000 $100,250
+Stockholders' equity $133,261 $140,960 $147,224 $136,328 $124,380
+----------
+We use the full-cost method of accounting. Under this method of
+accounting, our net capitalized costs to acquire, explore and develop oil
+and gas properties may not exceed the standardized measure of our proved
+reserves. If these capitalized costs exceed a ceiling amount, the excess
+is charged to expense.
+28
+ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
+OF OPERATIONS
+The following discussion is intended to assist in an understanding of our
+financial condition and results of operations. Our Consolidated Financial
+Statements and Notes thereto contain detailed information that should be
+referred to in conjunction with the following discussion. See Item 8. "Financial
+Statements and Supplementary Data."
+GENERAL
+We have been engaged in the exploration, development, acquisition and production
+of oil and gas properties since 1950. Our revenues, profitability and future
+growth and the carrying value of our oil and gas properties are substantially
+dependent on prevailing prices of oil and gas and our ability to find, develop
+and acquire additional oil and gas reserves that are economically recoverable.
+Our ability to maintain or increase our borrowing capacity and to obtain
+additional capital on attractive terms is also influenced by oil and gas prices.
+Significant events of our financial and operating results for the year ended
+December 31, 2003 included:
+- borrowing $185 million for a term of seven-years at an interest rate
+of 9.75% pursuant to a senior unsecured credit agreement;
+- the contribution of our 15% working interest in the Medusa spar
+production facilities into a limited liability company in return for
+approximately $25 million of cash and a 10% interest in the limited
+liability company which will earn a throughput fee for production
+processed in the Medusa area; and
+- the commencement of production from two of our deepwater
+discoveries, Medusa and Habanero, in late November 2003 which is
+expected to increase production for 2004 by approximately 80% over
+2003 levels.
+- a charge of $11.5 million to income tax expense as the result of
+establishing a valuation allowance against our deferred tax asset
+required by SFAS 109 "Accounting for Income Taxes". This charge was
+taken due to the negative evidence resulting from the cumulative
+losses incurred for the three year period ending December 31, 2003.
+Relevant accounting guidance suggests that positive future
+expectations about income are diminished by such losses. If the
+Company achieves profitable operations in 2004, the Company expects
+it will reverse a portion of the valuation allowance in an amount at
+least sufficient to eliminate any tax provision in that period. See
+Note 3 to the Company's Consolidated Financial Statements for a more
+detailed discussion.
+These financial transactions allowed us to redeem $62.9 million of senior
+subordinated notes which were maturing in 2004, redeem $85.0 million of 12%
+loans maturing in March 2005 and reduce the outstanding balance under our senior
+secured credit facility. As a result, we expect that planned 2004 capital
+expenditures of approximately $65 million will be funded with cash flows from
+operations and draws under our senior secured credit facility, if necessary. The
+current borrowing base of $45 million under the senior secured credit facility,
+which had $30.0 million outstanding against it on December 31, 2003, is
+currently under review and may be increased since a majority of our reserves for
+Medusa and Habanero are now classified as proved developed reserves. This credit
+facility matures on June 30, 2004 and we
+29
+anticipate extending the due date or replacing it with a facility with similar
+or more favorable terms. For a more detailed discussion of outstanding debt see
+Note 5 to our Consolidated Financial Statements.
+Our estimated net proved oil and gas reserves decreased at December 31, 2003 to
+217 billion cubic feet of natural gas equivalent (Bcfe). This represents a
+decrease of 8% from previous year-end 2002 estimated proved reserves of 236
+Bcfe.
+We incurred a major downward revision to proved reserves in 2002 at our
+Boomslang discovery. The initial exploratory well drilled at this location in
+1998 encountered 185 feet of pay. The well was drilled with mechanical problems
+and was subsequently determined not to be a viable well for completion and
+production of the estimated proved reserves encountered in this initial well. A
+second well, drilled in the fourth quarter of 2002, to serve as a production
+take point, was drilled in a down dip direction from the first well targeting
+what was anticipated to be a better sand development in the three separate
+reservoirs found in the first well, but still up dip of the lowest known
+hydrocarbons in the first well. Reservoir sand quality changed dramatically,
+reducing the estimated reservoir volumes found and booked as estimated proved
+reserves by the first well to an extent that the partners determined that the
+risk of development was not economic. Callon had a 40% working interest. The
+Company's proved reserves in the prior year included 7.2 million barrels of oil
+and 13 billion cubic feet of natural gas attributable to Boomslang.
+Prices for oil and gas are subject to large fluctuations in response to
+relatively minor changes in the supply of and demand for oil and gas, market
+uncertainty and a variety of additional factors beyond our control. These
+factors include weather conditions in the United States, the condition of the
+United States economy, the actions of the Organization of Petroleum Exporting
+Countries, governmental regulation, political stability in the Middle East and
+elsewhere, the foreign supply of crude oil and natural gas, the price of foreign
+imports and the availability of alternate fuel sources. Any substantial and
+extended decline in the price of crude oil or natural gas would have an adverse
+effect on our carrying value of our proved reserves, borrowing capacity,
+revenues, profitability and cash flows from operations. We use derivative
+financial instruments (see Note 6 and Item 7A. "Quantitative and Qualitative
+Disclosures About Market Risks") for price protection purposes on a limited
+amount of our future production and do not use them for trading purposes. On a
+Mcfe basis, natural gas represents 45% of the budgeted 2004 production and 34%
+of proved reserves at year-end 2003.
+Inflation has not had a material impact on us and is not expected to have a
+material impact on us in the future.
+SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
+RECENT ACCOUNTING PRONOUNCEMENTS. In June 1998, the Financial Accounting
+Standards Board ("FASB") issued Statement of Financial Accounting Standards No.
+133 ("SFAS 133"), Accounting for Derivative Instruments and Hedging Activities.
+The Statement establishes accounting and reporting standards requiring that
+every derivative instrument, including certain derivative instruments embedded
+in other contracts, be recorded in the balance sheet as either an asset or
+liability measured at its fair value. SFAS 133 requires us to report changes in
+the fair value of our derivative financial instruments that qualify as cash flow
+hedges in other comprehensive income, a component of stockholders' equity, until
+realized. We adopted SFAS 133 effective January 1, 2001.
+In June 2001, the FASB issued Statement of Financial Accounting Standards No.
+143, Accounting for Asset Retirement Obligations ("SFAS 143") effective for
+fiscal years beginning after June 15, 2002. SFAS 143 essentially requires
+entities to record the fair value of a liability for obligations associated with
+the retirement of tangible long-lived assets and the associated asset retirement
+costs. We adopted the
+30
+statement on January 1, 2003 resulting in a cumulative effect of accounting
+change of $181,000, net of tax. See Note 8 to our Consolidated Financial
+Statements.
+In December 2002, the FASB issued Statement of Financial Accounting Standards
+No. 148 ("SFAS 148"), "Accounting for Stock-Based Compensation-Transition and
+Disclosure -an amendment of SFAS No. 123." SFAS 148 amends SFAS 123 to provide
+alternative methods of transition for a voluntary change to the fair value based
+method of accounting for stock-based employee compensation. In addition, this
+statement amends the disclosure requirements of SFAS 123 to require disclosures
+in both annual and interim financial statements about the method of accounting
+for stock-based employee compensation and the effect of the method used on the
+reported results. SFAS 148 is effective for the year ended December 31, 2002 and
+for interim financial statements commencing in 2003. The adoption of this
+pronouncement by us did not have an impact on our financial condition or results
+of operations.
+In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
+Variable Interest Entities, an Interpretation of Accounting Research Bulletin
+(ARB) 51" ("FIN 46"). FIN 46 addresses consolidation by business enterprises of
+variable interest entities ("VIEs"). The primary objective of FIN 46 is to
+provide guidance on the identification of, and financial reporting for, entities
+over which control is achieved through means other than voting rights; such
+entities are known as VIEs. The provisions of FIN 46 are effective immediately
+for these variable interest entities created after January 31, 2003. On December
+24, 2003, the FASB issued a revision to FIN 46 which among other things deferred
+the effective date for certain variable interests created prior to January 31,
+2003. Application is required for interests in special-purpose entities in the
+periods ending after December 15, 2003 and application is required for all other
+types of variable interest entities in the periods ending after March 31, 2004.
+We adopted FIN 46, as revised, as of December 31, 2003, which had no impact on
+the financial statements.
+In June 2001, the FASB issued Statement of Financial Accounting Standards No.
+141 ("SFAS 141"), "Business Combinations," which requires the use of the
+purchase method of accounting for business combinations initiated after June 30,
+2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also
+issued Statement of Financial Accounting Standards No. 142 ("SFAS 142"),
+"Goodwill and Other Intangible Assets," which discontinues the practice of
+amortizing goodwill and indefinite lived intangible assets and initiates an
+annual review of impairment. The new standard also requires that all intangible
+assets be aggregated and presented as a separate line item in the balance sheet.
+The adoption of SFAS No. 141 and 142 had no impact on the Company's financial
+position or results of operations. A reporting issue has arisen regarding the
+application of certain provisions of SFAS No. 141 and 142 to companies in the
+oil and gas industry. The issue is whether SFAS No. 141 requires registrants to
+classify the costs of mineral rights associated with extracting oil and gas as
+intangible assets in the balance sheet, apart from other capitalized oil and gas
+property costs, and provide specific footnote disclosures. Historically, the
+Company has included the costs of mineral rights associated with extracting oil
+and gas as a component of oil and gas properties. These costs include those to
+acquire contract based drilling and mineral use rights such as delay rentals,
+lease bonuses, commissions and brokerage fees, and other leasehold costs.
+The Emerging Issues Task Force ("EITF") has added the treatment of oil and gas
+mineral rights to an upcoming agenda, which may result in a change in the
+classification of these amounts, as described above. The Company will continue
+to classify its oil and gas leasehold costs as tangible oil and gas properties
+until further guidance is provided. The Company's cash flows and results of
+operations would not be affected since such intangible assets would continue to
+be depleted and assessed for impairment in accordance with full cost accounting
+rules, as allowed by SFAS No. 142. Further, the Company believes
+31
+that the amounts that would be classified as intangible assets as of December
+31, 2003 and 2002, would be immaterial.
+PROPERTY AND EQUIPMENT. We follow the full-cost method of accounting for oil and
+gas properties whereby all costs incurred in connection with the acquisition,
+exploration and development of oil and gas reserves, including certain overhead
+costs, are capitalized into the "full-cost pool." The amounts we capitalize into
+the full-cost pool are depleted (charged against earnings) using the
+unit-of-production method. The full-cost method of accounting for our proved oil
+and gas properties requires that we make estimates based on assumptions as to
+future events which could change. These estimates are described below.
+Depreciation, Depletion and Amortization (DD&A) of Oil and Gas Properties. We
+calculate depletion by using the capitalized costs in our full-cost pool plus
+future development and abandonment costs (combined, the depletable base) and our
+estimated net proved reserve quantities. Capitalized costs added to the
+full-cost pool and other costs added to the depletable base include the
+following:
+- the cost of drilling and equipping productive wells, dry hole costs,
+acquisition costs of properties with proved reserves, delay rentals
+and other costs related to exploration and development of our oil
+and gas properties;
+- our payroll and general and administrative costs and costs related
+to fringe benefits paid to employees directly engaged in the
+acquisition, exploration and/or development of oil and gas
+properties as well as other directly identifiable general and
+administrative costs associated with such activities. Such
+capitalized costs do not include any costs related to our production
+of oil and gas or our general corporate overhead;
+- costs associated with properties that do not have proved reserves
+attributed to them are excluded from the full cost pool. These
+unevaluated property costs are added to the full cost pool at such
+time as wells are completed on the properties, the properties are
+sold or we determine these costs have been impaired. Our
+determination that a property has or has not been impaired (which is
+discussed below) requires that we make assumptions about future
+events;
+- our estimates of future costs to develop proved properties are added
+to the full cost pool for purposes of the DD&A computation. We use
+assumptions based on the latest geologic, engineering, regulatory
+and cost data available to us to estimate these amounts. However,
+the estimates we make are subjective and may change over time. Our
+estimates of future development costs are periodically updated as
+additional information becomes available; and
+- prior to the adoption of SFAS 143, estimated costs to dismantle,
+abandon and restore a proved property were added to the full cost
+pool for the purposes of DD&A. Subsequent to the adoption of SFAS
+143, effective January 1, 2003, these costs are included in the full
+cost pool. Such cost estimates are periodically updated as
+additional information becomes available. As discussed above under
+Accounting Pronouncements, specifically SFAS 143, beginning January
+1, 2003, we changed the method for which we account for such costs.
+Capitalized costs included in the full-cost pool are depleted and charged
+against earnings using the unit of production method. Under this method, we
+estimate our quantity of proved reserves at the beginning of each accounting
+period. For each barrel of oil equivalent produced during the period, we record
+a depletion charge equal to the amount included in the depletable base (net of
+accumulated depreciation, depletion and amortization) divided by our estimated
+net proved reserve quantities.
+Because we use estimates and assumptions to calculate proved reserves (as
+discussed below) and the amounts included in the full-cost pool, our depletion
+calculations will change if the estimates and assumptions are not realized. Such
+changes may be material.
+32
+Ceiling Test. Under the full-cost accounting rules, capitalized costs included
+in the full-cost pool, net of accumulated depreciation, depletion and
+amortization (DD&A), cost of unevaluated properties and deferred income taxes,
+may not exceed the present value of our estimated future net cash flows from
+proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or
+fair value of unproved properties included in the costs being amortized, net of
+related tax effects. These rules generally require that, in estimating future
+net cash flow, we assume that future oil and gas production will be sold at the
+unescalated market price for oil and gas received at the end of each fiscal
+quarter and that future costs to produce oil and gas will remain constant at the
+prices in effect at the end of the fiscal quarter. We are required to write-down
+and charge to earnings the amount, if any, by which these costs exceed the
+discounted future net cash flows, unless prices recover sufficiently before the
+date of our financial statements. Given the volatility of oil and gas prices, it
+is likely that our estimates of discounted future net cash flows from proved oil
+and gas reserves will change in the near term. If oil and gas prices decline
+significantly, even if only for a short period of time, it is possible that
+writedowns of oil and gas properties could occur in the future.
+Estimating Reserves and Present Values. Our estimates of quantities of proved
+oil and gas reserves and the discounted present value of such reserves at the
+end of each quarter are based on numerous assumptions which are likely to change
+over time. These assumptions include:
+- the prices at which we can sell our oil and gas production in the
+future. Oil and gas prices are volatile, but we are generally
+required to assume that they will not change from the prices in
+effect at the end of the quarter. In general, higher oil and gas
+prices will increase quantities of proved reserves and the present
+value of such reserves, while lower prices will decrease these
+amounts. Because our properties have relatively short productive
+lives, changes in prices will affect the present value more than
+quantities of oil and gas reserves; and
+- the costs to develop and produce our reserves and the costs to
+dismantle our production facilities when reserves are depleted.
+These costs are likely to change over time, but we are required to
+assume that costs in effect at the end of the quarter will not
+change. Increases in costs will reduce oil and gas quantities and
+present values, while decreases in costs will increase such amounts.
+Because our properties have relatively short productive lives,
+changes in costs will affect the present value more than quantities
+of oil and gas reserves.
+- the potential liability to pay royalties to the Mineral Management
+Service on some of the Company's properties which qualify for
+royalty relief under the Deep Water Royalty Relief Act could reduce
+proved reserves. See Note 7 of our Consolidated Financial Statements
+for a more detailed discussion of this potential liability.
+In addition, the process of estimating proved oil and gas reserves requires that
+our independent and internal reserve engineers exercise judgment based on
+available geological, geophysical and technical information. We have described
+the risks associated with reserve estimation and the volatility of oil and gas
+prices, under "Risk Factors" .
+Unproved Properties. Costs associated with properties that do not have proved
+reserves, including capitalized interest, are excluded from the full-cost pool.
+These unproved properties are included in the line item "Unevaluated properties
+excluded from amortization." Unproved property costs are transferred to the
+full-cost pool when wells are completed on the properties or the properties are
+sold. In addition, we are required to determine whether our unproved properties
+are impaired and, if so, add the costs of such properties to the full-cost pool.
+We determine whether an unproved property should be impaired by periodically
+reviewing our exploration program on a property by property basis. This
+determination may require the exercise of substantial judgment by our
+management.
+33
+DERIVATIVES. We use derivative financial instruments for price protection
+purposes on a limited amount of our future production and do not use them for
+trading purposes. Such derivatives were accounted for in years prior to 2001 as
+hedges and have been recognized as an adjustment to oil and gas sales in the
+period in which they are related. We currently use the accounting treatment for
+derivatives specified under SFAS 133.
+INCOME TAXES. We follow the asset and liability method of accounting for
+deferred income taxes prescribed by Statement of Financial Accounting Standards
+No. 109 ("SFAS 109") "Accounting for Income Taxes". The statement provides for
+the recognition of a deferred tax asset for deductible temporary timing
+differences, capital and operating loss carryforwards, statutory depletion
+carryforward and tax credit carryforwards, net of a "valuation allowance". The
+valuation allowance is provided for that portion of the asset, for which it is
+deemed more likely than not, that it will not be realized.
+SFAS 109 provides for the weighing of positive and negative evidence in
+determining whether it is more likely than not that a deferred tax asset is
+recoverable. We have incurred losses in 2002 and 2003 and have losses on an
+aggregate basis for the three-year period ended December 31, 2003. However, as
+discussed in Note 5, in December 2003 we refinanced nearly all our highest cost
+debt, incurring an early extinguishment loss of $5.6 million, but achieving
+significant interest savings in the future. In addition, as discussed in Note 5,
+the first two of our deepwater projects began production in November 2003, which
+is expected to result in a significant increase in 2004 production as compared
+to 2003. Nevertheless, relevant accounting guidance suggests that a recent
+history of cumulative losses constitutes significant negative evidence, and that
+future expectations about income are overshadowed by such recent losses. As a
+result, we established a valuation allowance of $11.5 million as of December 31,
+2003. If we achieve profitable operations in 2004, we expect to reverse a
+portion of the valuation allowance in an amount at least sufficient to eliminate
+any tax provision in that period. See Note 3 of our Consolidated Financial
+Statements for further disclosure.
+LIQUIDITY AND CAPITAL RESOURCES
+Our primary sources of capital are cash flows from operations, borrowings from
+financial institutions and the sale of debt and equity securities. Net cash and
+cash equivalents increased during 2003 to $8.7 million, up $2.9 million. Cash
+provided from operating activities during 2003 totaled $34.6 million, up from
+$12.2 million in 2002. Cash provided by operating activities during 2004 is
+expected to increase significantly due to the Medusa and Habanero deepwater
+projects commencing production in late November 2003. Dividends paid on
+preferred stock were $1.3 million. Most of our outstanding debt was restructured
+during December 2003. The restructuring of our debt is discussed in the
+following paragraphs.
+In December 2003 we borrowed $185 million pursuant to a senior unsecured credit
+facility with a stated interest rate of 9.75%. The net proceeds from the loans
+of $181.3 million were used to redeem $22.9 million of 10.125% senior
+subordinated notes due July 31, 2004, $40 million of 10.25% senior subordinated
+notes due September 15, 2004, $85 million of our 12% loans due March 31, 2005
+plus a 1% call premium of $850,000 and to reduce the balance outstanding under
+our senior secured revolving credit facility. A charge of $5.3 million was
+incurred in 2003 as a result of the early extinguishment of debt for the 12%
+loans due March 31, 2005 and a charge of approximately $1.4 million will be
+incurred in 2004 for the early extinguishment of the $22.9 million 10.125%
+senior subordinated notes due July 31, 2004 and the $40 million 10.25% senior
+subordinated notes due September 15, 2004. We exercised covenant defeasance
+under the indentures for the 10.125% and 10.25% notes on December 8, 2003 and
+distributed a required 30-
+34
+day redemption notice. The funds necessary to redeem the notes were placed in
+trust and the trustee paid the holders of the notes on January 8, 2004. The
+funds in trust were classified on our December 31, 2003 balance sheet as
+restricted cash. In conjunction with the new senior unsecured notes, we issued
+detachable warrants to purchase 2.775 million of our common stock at an exercise
+price of $10 per share. This senior unsecured debt matures December 8, 2010. See
+Note 5 of our Consolidated Financial Statements for a more detailed description
+of these securities.
+In December 2003, we announced the formation of a limited liability company,
+Medusa Spar LLC, which now owns a 75% undivided ownership interest in the
+deepwater spar production facilities on our Medusa Field in the Gulf of Mexico.
+We contributed a 15% undivided ownership interest in the production facility to
+the LLC in return for approximately $25 million in cash and a 10% ownership
+interest in the LLC. Our cash proceeds were used to reduce the balance
+outstanding under our senior secured credit facility. The LLC will earn a tariff
+based upon production volume throughput from the Medusa area. We are obligated
+to process our share of production from the Medusa field and any future
+discoveries in the area through the spar production facilities. The LLC used the
+cash proceeds from $83.7 of non-recourse financing and a cash contribution by
+one of the LLC owners to acquire its 75% interest in the spar. The balance of
+the LLC is owned by Oceaneering International, Inc. (NYSE:OII) and Murphy Oil
+Corporation (NYSE:MUR). We are accounting for our 10% ownership interest in the
+LLC under the equity method.
+Our remaining maturities for unsecured debt, excluding the $185 million in 9.75%
+loans due 2010, consists of $10 million of the 12% loans with a due date of
+March 31, 2005 and $33 million of 11% senior subordinated notes with a due date
+of December 15, 2005. These 2005 maturities will be retired by our primary
+sources of capital which are cash flows from operations, borrowings from
+financial institutions and the sale of debt and equity securities. See Note 5 of
+our Consolidated Financial Statements for a more detailed description of these
+securities
+Borrowings under our senior secured credit facility are secured by mortgages
+covering substantially all of our producing oil and gas properties. This
+facility had a $45 million borrowing base on December 31, 2003 with $30 million
+outstanding against it. As of February 29, 2004, $20 million in loans were
+outstanding under the facility. The borrowing base is currently being reviewed
+by the lenders and could be increased due to our proved producing reserves
+increasing as a result of the Medusa and Habanero fields commencing production
+late in the fourth quarter of 2003. The facility expires on June 30, 2004 and we
+are currently reviewing options to extend the maturity date or to replace the
+facility with one that is similar or with more favorable terms. See Note 5 of
+our Consolidated Financial Statements for a more detailed description of the
+credit facility.
+Outstanding debt on December 31, 2003 was $308.1 million, and after retirement
+of the 2004 notes using restricted cash on January 8, 2004, debt was $245.2
+million, compared to $249.6 million on December 31, 2002. The senior secured
+credit facility, our two senior unsecured credit facilities and the indenture
+for our senior subordinated debt contain various covenants including
+restrictions on additional indebtedness and payment of cash dividends as well as
+maintenance of certain financial ratios. We were in compliance with these
+covenants at December 31, 2003.
+Capital expenditure plans for 2004 include:
+- the completion of the development projects for Medusa and Habanero;
+- the drilling of a satellite prospect in the Medusa field;
+- the drilling and completion of a proved undeveloped location in the
+Mobile Blocks 952/953/955 field;
+- the acquisition of seismic and leases; and
+35
+- discretionary capital projects for the exploratory drilling of deep
+shelf prospects we developed through our 3-D seismic partnership
+using AVO technology.
+We anticipate that cash flow generated during 2004 and current availability
+under our senior secured credit facility, if necessary, will provide the $65
+million, which includes capitalized interest and general and administrative
+expenses, of capital necessary to fund these planned capital expenditures and
+the current portion of our asset retirement obligation in the amount of $8.6
+million.
+The following table describes our outstanding contractual obligations (in
+thousands) as of December 31, 2003:
+CONTRACTUAL LESS THAN ONE-THREE FOUR-FIVE AFTER-FIVE
+OBLIGATIONS TOTAL ONE YEAR YEARS YEARS YEARS
+----------- ------- --------- --------- --------- ----------
+Senior Secured Revolving Credit Facility $30,000 $30,000(b) $ -- $ -- $ --
+10.125% Senior Subordinated Notes 22,915 22,915(a) -- -- --
+10.25% Senior Subordinated Notes 40,000 40,000(a) -- -- --
+12% Senior Loans 10,000 -- 10,000 -- --
+9.75% Senior Unsecured Credit Facility 185,000 -- -- -- 185,000
+11% Senior Subordinated Notes 33,000 -- 33,000 -- --
+Capital lease (future minimum payments) 4,421 1,890 1,261 577 693
+Throughput Commitments:
+Medusa Spar 23,128 5,628 8,660 5,532 3,308
+Medusa Oil Pipeline 1,129 269 460 186 214
+(a) These notes were retired with restricted cash on January 8, 2004.
+(b) This facility matures June 30, 2004 and is expected to be extended or
+replaced with a new facility.
+36
+RESULTS OF OPERATIONS
+The following table sets forth certain operating information with respect to our
+oil and gas operations for each of the three years in the period ended December
+31, 2003.
+DECEMBER 31,
+---------------------------------
+2003(A) 2002(A)(B) 2001(A)(B)
+------- ---------- ----------
+Production:
+Oil (MBbls) 268 226 273
+Gas (MMcf) 12,315 14,215 13,566
+Total production (MMcfe) 13,923 15,571 15,206
+Average daily production (MMcfe) 38.1 42.7 41.7
+Average sales price:
+Oil (per Bbl) $ 28.72 $ 23.11 $ 22.95
+Gas (per Mcf) $ 5.36 $ 3.94 $ 3.96
+Total (per Mcfe) $ 5.29 $ 3.93 $ 3.95
+Oil and Gas revenues:
+Gas revenue $66,001 $55,949 $53,729
+Oil revenue 7,696 5,222 6,281
+------- ------- -------
+Total $73,697 $61,171 $60,010
+======= ======= =======
+Oil and gas production costs:
+Lease operating expenses $11,301 $11,030 $11,252
+Additional per Mcfe data:
+Sale price $ 5.29 $ 3.93 $ 3.95
+Lease operating expenses .81 .71 .73
+------- ------- -------
+Operating margin $ 4.48 $ 3.22 $ 3.22
+======= ======= =======
+Depletion $ 2.03 $ 1.73 $ 1.37
+Accretion $ .21 $ -- $ --
+General and administrative (net of management fees) $ .34 $ .30 $ .30
+(a) Average sales price includes hedging gains and losses.
+(b) Production volumes include 1,200 MMcf for the year 2002 and 2,300 MMcf for
+2001, at an average price of $2.08 per Mcf associated with a volumetric
+production payment.
+37
+OFF-BALANCE SHEET ARRANGEMENTS
+In December 2003, we announced the formation of a limited liability company,
+Medusa Spar LLC, which now owns a 75% undivided ownership interest in the
+deepwater spar production facilities on our Medusa Field in the Gulf of Mexico.
+We contributed a 15% undivided ownership interest in the production facility to
+Medusa Spar LLC in return for approximately $25 million in cash and a 10%
+ownership interest in the LLC. The LLC will earn a tariff based upon production
+volume throughput from the Medusa area. We are obligated to process our share of
+production from the Medusa field and any future discoveries in the area through
+the spar production facilities. This arrangement allows us to defer the cost of
+the Spar production facility over the life of the Medusa field. Our cash
+proceeds were used to reduce the balance outstanding under our senior secured
+credit facility. The LLC used the cash proceeds from $83.7 of non-recourse
+financing and a cash contribution by one of the LLC owners to acquire its 75%
+interest in the spar. The balance of Medusa Spar LLC is owned by Oceaneering
+International, Inc. (NYSE:OII) and Murphy Oil Corporation (NYSE:MUR). We are
+accounting for our 10% ownership interest in the LLC under the equity method.
+SEC INQUIRIES REGARDING RESERVE INFORMATION
+Beginning in October 2002 we received a series of inquiries from the SEC
+regarding our Annual Report on Form 10-K for the year ended December 31, 2001
+requesting supplemental information concerning our operations in the Gulf of
+Mexico. The comment letters requested information about the procedures we used
+to classify our deepwater reserves as proved and requested that our financials
+be restated to reflect the removal of the Boomslang reserves as proved for all
+prior periods during which such reserves were reported as proved. We have
+reviewed the SEC comments with our independent petroleum reserve engineers,
+Huddleston & Co., Inc., of Houston, Texas. Both Huddleston & Co. and we believe
+that such deepwater reserves are properly classified as proved. The Company has
+responded to all of the SEC inquiries.
+COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2003 AND
+2002
+OIL AND GAS REVENUES
+Total oil and gas revenues increased 20% from $61.2 million in 2002 to $73.7 in
+2003 while total production for 2003 decreased by 11% versus 2002. Realized oil
+and gas prices were substantially higher when compared to the same period in
+2002 and accounted for the increase in revenue. Gas revenues for 2002 included
+$9.2 million of non-cash revenue related to the Enron derivatives discussed in
+Note 6 to the Consolidated Financial Statements.
+Gas production during 2003 totaled 12.3 Bcf and generated $66.0 million in
+revenues compared to 14.2 Bcf and $55.9 million in revenues during the same
+period in 2002. Average gas prices for 2003 were $5.36 per Mcf compared to $3.94
+per Mcf during the same period last year. The decrease in production was
+primarily due to the depletion of the lowest productive zone of the East Cameron
+Block 294 field. The well at East Cameron Block 294 was returned to production
+after a recompletion to a behind pipe zone in the third quarter of 2003. Also,
+the sale of the North and Northwest Dauphin Island fields in the fourth quarter
+of 2002 and the normal and expected declines in production from other properties
+contributed to the variance.
+Oil production during 2003 totaled 268,000 barrels and generated $7.7 million in
+revenues compared to 226,000 barrels and $5.2 million in revenues for the same
+period in 2002. Average oil prices received in
+38
+2003 were $28.72 per barrel compared to $23.11 per barrel in 2002. The increase
+in production was due to the initial production from our deepwater discoveries,
+Medusa and Habanero, which began producing late in the fourth quarter of 2003.
+This was offset slightly by downtime for maintenance to the facility and
+equipment at the Big Escambia Creek Field operated by ExxonMobil Corporation and
+normal and expected declines in production from older properties.
+LEASE OPERATING EXPENSES
+Lease operating expenses for 2003 increased by 2% to $11.3 million compared to
+$11.0 million for the same period in 2002. The increase was primarily due to the
+increase in lease operating expenses for the Mobile Block 864 area resulting
+from the implementation of the accelerated production program in the second
+quarter of 2002 and lease operating expenses related to our deepwater
+discoveries, Medusa and Habanero, which began producing late in the fourth
+quarter of 2003. The increase was slightly offset as a result of the sale of
+North and Northwest Dauphin Island fields in the fourth quarter of 2002 which
+reduced lease operating expenses for 2003.
+DEPRECIATION, DEPLETION AND AMORTIZATION
+Depreciation, depletion and amortization for 2003 and 2002 were $28.3 million
+and $27.1 million, respectively. The 4% increase was due primarily to the
+downward reserve revisions for our Boomslang field at Ewing Bank Block 994 at
+the end of 2002. This decrease in estimated proved reserves increased the
+depletable cost per unit of production.
+ACCRETION EXPENSE
+Accretion expense of $2.9 million represents accretion for our asset retirement
+obligations for 2003.
+GENERAL AND ADMINISTRATIVE
+General and administrative expenses for 2003, net of amounts capitalized, were
+$4.7 million and flat with the amount incurred in 2002.
+INTEREST EXPENSE
+Interest expense increased by 17% in 2003 to $30.6 million compared to $26.1
+million in 2002. This was a result of higher debt levels.
+LOSS ON EARLY EXTINGUISHMENT OF DEBT
+A loss of $5.6 million was incurred in December of 2003 for the write-off of
+deferred financing costs and bond discounts associated with the early
+extinguishment of $85 million of the 12% loans due in 2005 plus a 1% pre-payment
+premium.
+INCOME TAXES
+The income tax expense of $8.4 million in 2003 was primarily due to a charge of
+$11.5 million to establish a valuation allowance against our deferred tax asset
+required by SFAS 109 "Accounting for Income Taxes". This charge was taken due to
+the negative evidence resulting from the cumulative losses incurred for the
+three year period ending December 31, 2003. Relevant accounting guidance
+suggests that positive future expectations about income are diminished by such
+losses. If the Company achieves
+39
+profitable operations in 2004, the Company expects it will reverse a portion of
+the valuation allowance in an amount at least sufficient to eliminate any tax
+provision in that period. See Note 3 to the Company's Consolidated Financial
+Statements for a more detailed discussion.
+COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2002 AND
+2001
+OIL AND GAS REVENUES
+Oil and gas revenues for 2002 were $61.2 million, a 2% increase from the 2001
+amount of $60.0 million. Oil and gas production of 15,571 MMcfe during 2002
+increased as well from the 2001 amount of 15,206 MMcfe.
+Oil production decreased from 273,000 barrels in 2001 to 226,000 barrels in 2002
+but the average sales price increased from $22.95 in 2001 to $23.11 in 2002. As
+a result, oil revenues dropped from $6.3 million in 2001 to $5.2 million in
+2002. The production decrease was primarily due to older properties' normal and
+expected decline in production.
+Gas revenues for 2002 were $55.9 million based on sales of 14.2 Bcf at an
+average sales price of $3.94 per Mcf. For 2001, gas revenues were $53.7 million
+based on production of 13.6 Bcf sold at an average sales price of $3.96 per Mcf.
+Our gas production in 2002 increased when compared to last year due primarily to
+the acceleration program at Mobile Blocks 952/953/955 area initiated in the
+fourth quarter of 2001.
+LEASE OPERATING EXPENSES
+Lease operating expenses remained relatively stable at $11.0 million ($.71 per
+Mcfe) in 2002 compared to $11.3 million ($.73 per Mcfe) in 2001.
+DEPRECIATION, DEPLETION AND AMORTIZATION
+Depreciation, depletion and amortization increased by 28% due in large part to
+the downward reserve revisions at Boomslang. This decrease in estimated proved
+reserves, over which depletable costs are amortized, increased the per unit
+depletion rate, while production remained relatively constant between years.
+Total charges increased from $21.1 million or $1.39 per Mcfe in 2001, to $27.1
+million, or $1.74 per Mcfe in 2002.
+GENERAL AND ADMINISTRATIVE
+General and administrative expenses for 2002 were $4.7 million, or $.30 per
+Mcfe, compared to $4.6 million, or $.30 per Mcfe, in 2001.
+INTEREST EXPENSE
+Interest expense for 2002 was $26.1 million increasing from $12.8 million in
+2001. This is a result of an increase in our long-term debt as well as higher
+interest rates associated with additional debt incurred in 2002.
+40
+INCOME TAXES
+Our 2002 results included a deferred income tax benefit of $900,000. We
+evaluated the deferred income tax asset in light of our reserve quantity
+estimates, our long-term outlook for oil and gas prices and our expected level
+of future revenues and expenses. We believe it is more likely than not, based
+upon this evaluation, that we will realize the recorded deferred income tax
+asset. However, there is no assurance that such asset will ultimately be
+realized.
+41
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
+The Company's revenues are derived from the sale of its crude oil and natural
+gas production. In recent months, the prices for oil and gas have increased;
+however, they remain extremely volatile and sometimes experience large
+fluctuations as a result of relatively small changes in supplies, weather
+conditions, economic conditions and government actions. The Company enters into
+derivative financial instruments to hedge oil and gas price risks for the
+production volumes to which the hedge relates. The derivatives reduce the
+Company's exposure on the hedged volumes to decreases in commodity prices and
+limit the benefit the Company might otherwise have received from any increases
+in commodity prices on the hedged volumes.
+The Company also enters into price "collars" to reduce the risk of changes in
+oil and gas prices. Under these arrangements, no payments are due by either
+party so long as the market price is above the floor price set in the collar and
+below the ceiling. If the price falls below the floor, the counter-party to the
+collar pays the difference to the Company and if the price is above the ceiling,
+the counter-party receives the difference from the Company. The Company enters
+into these various agreements to reduce the effects of volatile oil and gas
+prices and does not enter into hedge transactions for speculative purposes. See
+Note 6 to the Consolidated Financial Statements for a description of the
+Company's hedged position at December 31, 2003. There have been no significant
+changes in market risks faced by the Company since the end of 2003.
+Based on projected annual sales volumes for 2004 (excluding forecast production
+increases over 2003), a 10% decline in the prices we receive for our crude oil
+and natural gas production would have an approximate $13.7 million impact on our
+revenues.
+42
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
+Page
+---------
+Report of Independent Auditors 44 and 45
+Consolidated Balance Sheets as of December 31, 2003 46
+and 2002
+Consolidated Statements of Operations for Each of the Three Years
+in the Period Ended December 31, 2003 47
+Consolidated Statements of Stockholders' Equity
+for Each of the Three Years in the Period Ended December 31, 2003 48
+Consolidated Statements of Cash Flows for Each of the Three Years
+in the Period Ended December 31, 2003 49
+Notes to Consolidated Financial Statements 50
+43
+REPORT OF INDEPENDENT AUDITORS
+The Stockholders and Board of Directors
+Callon Petroleum Company
+We have audited the accompanying consolidated balance sheets of Callon
+Petroleum Company as of December 31, 2003 and 2002, and the related consolidated
+statements of operations, stockholders' equity and cash flows for the two years
+in the period ended December 31, 2003. These financial statements are the
+responsibility of the Company's management. Our responsibility is to express an
+opinion on these financial statements based on our audits. The financial
+statements of Callon Petroleum Company as of December 31, 2001 and for the year
+then ended, were audited by other auditors who have ceased operations and whose
+report dated March 29, 2002, expressed an unqualified opinion on those
+statements and included an explanatory paragraph that disclosed the change in
+the Company's method of accounting for derivative instruments and hedging
+activities discussed in Note 2 to those financial statements.
+We conducted our audits in accordance with auditing standards generally
+accepted in the United States. Those standards require that we plan and perform
+the audit to obtain reasonable assurance about whether the financial statements
+are free of material misstatement. An audit includes examining, on a test basis,
+evidence supporting the amounts and disclosures in the financial statements. An
+audit also includes assessing the accounting principles used and significant
+estimates made by management, as well as evaluating the overall financial
+statement presentation. We believe that our audits provide a reasonable basis
+for our opinion.
+In our opinion, the financial statements referred to above present fairly,
+in all material respects, the consolidated financial position of Callon
+Petroleum Company as of December 31, 2003 and 2002, and the results of its
+operations and its cash flows for the two years in the period ended December 31,
+2003, in conformity with accounting principles generally accepted in the United
+States.
+As discussed in Note 1 to the financial statements, effective January 1,
+2003, the Company adopted Statement of Financial Accounting Standards No. 143,
+"Accounting for Asset Retirement Obligations".
+ERNST & YOUNG LLP
+New Orleans, Louisiana
+March 3, 2004
+44
+The following report is a copy of the audit report previously issued by Arthur
+Andersen LLP in connection with Callon Petroleum Company's annual report on Form
+10-K for the year ended December 31, 2001. This audit report has not been
+reissued by Arthur Andersen LLP in connection with this filing on form 10-K for
+the year ended December 31, 2003. The consolidated balance sheet as of December
+31, 2000 and the consolidated statements of operations, stockholders' equity and
+cash flows for the year ended December 31, 2000, mentioned in the report, are
+not required in the Company's annual report for 2003 and are therefore not
+presented among the financial statements in this annual report.
+REPORT OF INDEPENDENT AUDITORS
+To the Stockholders and Board of Directors of Callon Petroleum Company:
+We have audited the accompanying consolidated balance sheets of Callon
+Petroleum Company (a Delaware corporation) and subsidiaries as of December 31,
+2001 and 2000, and the related consolidated statements of operations,
+stockholders' equity and cash flows for each of the three years in the period
+ended December 31, 2001. These financial statements are the responsibility of
+the Company's management. Our responsibility is to express an opinion on these
+financial statements based on our audits.
+We conducted our audits in accordance with auditing standards generally
+accepted in the United States. Those standards require that we plan and perform
+the audit to obtain reasonable assurance about whether the financial statements
+are free of material misstatement. An audit includes examining, on a test basis,
+evidence supporting the amounts and disclosures in the financial statements. An
+audit also includes assessing the accounting principles used and significant
+estimates made by management, as well as evaluating the overall financial
+statement presentation. We believe that our audits provide a reasonable basis
+for our opinion.
+In our opinion, the financial statements referred to above present fairly,
+in all material respects, the financial position of Callon Petroleum Company and
+subsidiaries, as of December 31, 2001 and 2000, and the results of their
+operations and their cash flows for each of the three years in the period ended
+December 31, 2001, in conformity with accounting principles generally accepted
+in the United States.
+As discussed in Note 2 to the consolidated financial statements effective
+January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivative
+Instruments and Hedging Activities."
+ARTHUR ANDERSEN LLP
+New Orleans, Louisiana
+MARCH 29, 2002
+45
+CALLON PETROLEUM COMPANY
+CONSOLIDATED BALANCE SHEETS
+(IN THOUSANDS, EXCEPT SHARE DATA)
+DECEMBER 31,
+---------------------
+2003 2002
+--------- ---------
+ASSETS
+Current assets:
+Cash and cash equivalents $ 8,700 $ 5,807
+Restricted cash 63,345 --
+Accounts receivable 10,117 10,875
+Other current assets 3,606 570
+--------- ---------
+Total current assets 85,768 17,252
+--------- ---------
+Oil and gas properties, full-cost accounting method:
+Evaluated properties 802,912 762,918
+Less accumulated depreciation, depletion and amortization (447,000) (426,254)
+--------- ---------
+355,912 336,664
+Unevaluated properties excluded from amortization 34,251 40,997
+--------- ---------
+Total oil and gas properties 390,163 377,661
+--------- ---------
+Pipeline and other facilities, net -- 853
+Other property and equipment, net 1,547 1,890
+Deferred tax asset -- 8,767
+Long-term gas balancing receivable 1,101 761
+Restricted investments 7,420 --
+Investment in Medusa Spar LLC 8,471 --
+Other assets, net 1,562 3,429
+--------- ---------
+Total assets $ 496,032 $ 410,613
+========= =========
+LIABILITIES AND STOCKHOLDERS' EQUITY
+Current liabilities:
+Accounts payable and accrued liabilities $ 16,020 $ 12,498
+Undistributed oil and gas revenues 897 1,109
+Accrued net profits interest payable 1,886 1,707
+Asset retirement obligations, current portion 8,571 --
+Current maturities of long-term debt 93,223 1,320
+--------- ---------
+Total current liabilities 120,597 16,634
+--------- ---------
+Long-term debt-excluding current maturities 214,885 248,269
+Accounts payable and accrued liabilities to be refinanced -- 3,861
+Asset retirement obligations 25,120 --
+Accrued retirement benefits 189 204
+Other long-term liabilities 1,980 685
+--------- ---------
+Total liabilities 362,771 269,653
+--------- ---------
+Stockholders' equity:
+Preferred Stock, $.01 par value; 2,500,000 shares
+authorized; 600,861 shares of Convertible
+Exchangeable Preferred Stock, Series A issued
+and outstanding at December 31, 2003
+with a liquidation preference of $15,021,525 6 6
+Common Stock, $.01 par value; 20,000,000 shares
+authorized; 13,935,311 shares and 13,900,466 shares
+outstanding at December 31, 2003 and 2002, respectively 139 139
+Capital in excess of par value 169,036 158,370
+Unearned restricted stock compensation (372) (826)
+Accumulated other comprehensive income (loss) (20) (469)
+Retained earnings (deficit) (35,528) (16,260)
+--------- ---------
+Total stockholders' equity 133,261 140,960
+--------- ---------
+Total liabilities and stockholders' equity $ 496,032 $ 410,613
+========= =========
+The accompanying notes are an integral part of these financial statements.
+46
+CALLON PETROLEUM COMPANY
+CONSOLIDATED STATEMENTS OF OPERATIONS
+FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
+(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
+2003 2002 2001
+-------- -------- --------
+Operating revenues:
+Oil and gas sales $ 73,697 $ 61,171 $ 60,010
+-------- -------- --------
+Operating expenses:
+Lease operating expenses 11,301 11,030 11,252
+Depreciation, depletion and amortization 28,253 27,096 21,081
+General and administrative 4,713 4,705 4,635
+Accretion expense 2,884 -- --
+Loss on mark-to-market commodity derivative contracts 535 708 --
+-------- -------- --------
+Total operating expenses 47,686 43,539 36,968
+-------- -------- --------
+Income from operations 26,011 17,632 23,042
+-------- -------- --------
+Other (income) expenses:
+Interest expense 30,614 26,140 12,805
+Other income (444) (1,004) (1,742)
+Loss on early extinguishment of debt 5,573 -- --
+Gain on sale of pipeline -- (2,454) --
+Gain on sale of Enron derivatives -- (2,479) --
+Writedown of Enron derivatives -- -- 9,186
+-------- -------- --------
+Total other (income) expenses 35,743 20,203 20,249
+-------- -------- --------
+Income (loss) before income taxes (9,732) (2,571) 2,793
+Income tax expense (benefit) 8,432 (900) 977
+-------- -------- --------
+Net income (loss) before Medusa Spar LLC and cumulative
+effect of change in accounting principle (18,164) (1,671) 1,816
+Loss from Medusa Spar LLC, net of tax (8) -- --
+-------- -------- --------
+Income (loss) before cumulative effect of change in
+accounting principle (18,172) (1,671) 1,816
+Cumulative effect of change in accounting principle, net of tax 181 -- --
+-------- -------- --------
+Net income (loss) (17,991) (1,671) 1,816
+Preferred stock dividends 1,277 1,277 1,277
+-------- -------- --------
+Net income (loss) available to common shares $(19,268) $ (2,948) $ 539
+======== ======== ========
+Net income (loss) per common share:
+Basic
+Net income (loss) available to common before cumulative
+effect of change in accounting principle $ (1.42) $ (0.22) $ .04
+Cumulative effect of change in accounting principle, net of tax 0.01 -- --
+-------- -------- --------
+Net income (loss) available to common $ (1.41) $ (0.22) $ .04
+======== ======== ========
+Diluted
+Net income (loss) available to common before cumulative
+effect of change in accounting principle $ (1.42) $ (0.22) $ .04
+Cumulative effect of change in accounting principle, net of tax 0.01 -- --
+-------- -------- --------
+Net income (loss) available to common $ (1.41) $ (0.22) $ .04
+======== ======== ========
+Shares used in computing net income (loss):
+Basic 13,662 13,387 13,273
+======== ======== ========
+Diluted 13,662 13,387 13,366
+======== ======== ========
+The accompanying notes are an integral part of these financial statements.
+47
+CALLON PETROLEUM COMPANY
+CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
+(IN THOUSANDS)
+Unearned Accumulated Total
+Restricted Capital in Other Retained Stock-
+Preferred Common Stock Excess of Comprehensive Earnings holders'
+Stock Stock Compensation Par Value Income (Loss) (Deficit) Equity
+--------- ------ ------------ ---------- ------------- ------------- ---------
+Balances, December 31, 2000 $ 6 $133 $ -- $ 150,040 $ -- $ (13,851) $136,328
+-------- ---- ----- --------- ------- --------- --------
+Comprehensive income:
+Net income -- -- -- -- -- 1,816
+Other comprehensive income -- -- -- -- 5,971 --
+--------
+Total comprehensive income 7,787
+Preferred stock dividend -- -- -- -- -- (1,277) (1,277)
+Shares issued pursuant to employee
+benefit and option plan -- 1 -- 942 -- -- 943
+Employee stock purchase plan -- -- -- 357 -- -- 357
+Tax benefits related to stock
+compensation plans -- -- -- 18 -- -- 18
+Warrants -- -- -- 3,068 -- -- 3,068
+-------- ---- ----- --------- ------- --------- --------
+Balances, December 31, 2001 6 134 -- 154,425 5,971 (13,312) 147,224
+-------- ---- ----- --------- ------- --------- --------
+Comprehensive income:
+Net loss -- -- -- -- -- (1,671)
+Other comprehensive loss -- -- -- -- (6,440) --
+--------
+Total comprehensive loss (8,111)
+Preferred stock dividends -- -- -- -- -- (1,277) (1,277)
+Shares issued pursuant to employee
+benefit and option plan -- 1 -- 770 -- -- 771
+Employee stock purchase plan -- -- -- 79 -- -- 79
+Tax benefits related to stock
+compensation plans -- -- -- (29) -- -- (29)
+Restricted stock -- 3 (826) 1,849 -- -- 1,026
+Warrants -- 1 -- 1,276 -- -- 1,277
+-------- ---- ----- --------- ------- --------- --------
+Balances, December 31, 2002 6 139 (826) 158,370 (469) (16,260) 140,960
+-------- ---- ----- --------- ------- --------- --------
+Comprehensive income:
+Net loss -- -- -- -- -- (17,991)
+Other comprehensive income -- -- -- -- 449 --
+--------
+Total comprehensive loss (17,542)
+Preferred stock dividends -- -- -- -- -- (1,277) (1,277)
+Shares issued pursuant to employee
+benefit and option plan -- 1 -- 427 -- -- 428
+Employee stock purchase plan -- -- -- 127 -- -- 127
+Restricted stock -- (1) 454 (516) -- -- (63)
+Warrants -- -- -- 10,628 -- -- 10,628
+-------- ---- ----- --------- ------- --------- --------
+Balances, December 31, 2003 $ 6 $139 $(372) $ 169,036 $ (20) $ (35,528) $133,261
+======== ==== ===== ========= ======= ========= ========
+The accompanying notes are an integral part of these financial statements.
+48
+CALLON PETROLEUM COMPANY
+CONSOLIDATED STATEMENTS OF CASH FLOWS
+FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
+(IN THOUSANDS)
+2003 2002 2001
+--------- -------- --------
+Cash flows from operating activities:
+Net income (loss) $ (17,991) $ (1,671) $ 1,816
+Adjustments to reconcile net income (loss) to
+cash provided by operating activities:
+Depreciation, depletion and amortization 29,264 27,774 21,709
+Accretion expense 2,884 -- --
+Amortization of deferred costs 6,568 5,521 2,485
+Non-cash loss on early extinguishment of debt 4,423
+Amortization of deferred production payment revenue -- (2,406) (4,830)
+Cumulative effect of change in accounting principle (181) -- --
+Non-cash derivative income -- (9,186) --
+Non-cash mark-to-market commodity derivative contracts 487 708 --
+Non-cash charge related to compensation plans 858 1,267 942
+Deferred income tax expense (benefit) 8,432 (900) 977
+Gain on sale of pipeline -- (2,454) --
+Writedown of Enron derivatives -- -- 9,186
+Changes in current assets and liabilities:
+Accounts receivable, trade (1,438) (4,967) 3,336
+Advance to operators (1,501) (98) 1,131
+Other current assets (1,166) (6) (2)
+Current liabilities 5,185 3,198 (8,782)
+Investment in derivative contracts -- (1,687) --
+Increase in accounts payable and accrued liabilities
+to be refinanced -- -- 9,558
+Change in gas balancing receivable (340) (288) 170
+Change in gas balancing payable (491) (390) 355
+Change in other long-term liabilities (15) 67 (1,749)
+Change in other assets, net (349) (2,315) (1,071)
+--------- -------- --------
+Cash provided (used) by operating activities 34,629 12,167 35,231
+--------- -------- --------
+Cash flows from investing activities:
+Capital expenditures (50,705) (66,023) (113,833)
+Sale of Medusa Spar to Medusa Spar, LLC 24,908 -- --
+Proceeds from sale of pipeline and other facilities 1,500 6,784 --
+Cash proceeds from sale of mineral interests 982 4,492 1,195
+--------- -------- --------
+Cash provided (used) by operating activities (23,315) (54,747) (112,638)
+--------- -------- --------
+Cash flows from financing activities:
+Change in accounts payable and accrued liability to be refinanced (3,861) (5,697) --
+Increase in debt 198,000 109,900 155,000
+Payment on debt (133,000) (58,085) (84,900)
+Restricted cash (63,345) -- --
+Debt issuance costs (3,745) (2,291) (2,374)
+Equity issued related to employee stock plans 127 79 357
+Capital lease (1,320) (1,129) 5,612
+Cash dividends on preferred stock (1,277) (1,277) (1,277)
+--------- -------- --------
+Cash provided (used) by financing activities (8,421) 41,500 72,418
+--------- -------- --------
+Net increase (decrease) in cash and cash equivalents 2,893 (1,080) (4,989)
+Cash and cash equivalents:
+Balance, beginning of period 5,807 6,887 11,876
+--------- -------- --------
+Balance, end of period $ 8,700 $ 5,807 $ 6,887
+========= ======== ========
+The accompanying notes are an integral part of these financial statements.
+49
+CALLON PETROLEUM COMPANY
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+1. ORGANIZATION
+GENERAL
+Callon Petroleum Company ("the Company" or "Callon") was organized under the
+laws of the state of Delaware in March 1994 to serve as the surviving entity in
+the consolidation and combination of several related entities (referred to
+herein collectively as the "Constituent Entities"). The combination of the
+businesses and properties of the Constituent Entities with the Company was
+completed on September 16, 1994 ("Consolidation").
+As a result of the Consolidation, all of the businesses and properties of the
+Constituent Entities are owned (directly or indirectly) by the Company. Certain
+registration rights were granted to the stockholders of certain of the
+Constituent Entities. See Note 7.
+The Company and its predecessors have been engaged in the acquisition,
+development and exploration of crude oil and natural gas since 1950. The
+Company's properties are geographically concentrated in Louisiana, Alabama,
+Texas and offshore Gulf of Mexico.
+2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
+PRINCIPLES OF CONSOLIDATION AND REPORTING
+The Consolidated Financial Statements include the accounts of the Company, and
+its subsidiary, Callon Petroleum Operating Company ("CPOC"). CPOC also has
+subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing,
+Inc. All intercompany accounts and transactions have been eliminated. Certain
+prior year amounts have been reclassified to conform to presentation in the
+current year.
+USE OF ESTIMATES
+The preparation of financial statements in conformity with generally accepted
+accounting principles requires management to make estimates and assumptions that
+affect the reported amounts of assets and liabilities and disclosure of
+contingent assets and liabilities at the date of the financial statements and
+the reported amounts of revenues and expenses during the reporting period.
+Actual results could differ from those estimates.
+ACCOUNTING PRONOUNCEMENTS
+In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement
+of Financial Accounting Standards No. 133 ("SFAS 133"), Accounting for
+Derivative Instruments and Hedging Activities. The Statement establishes
+accounting and reporting standards requiring that every derivative instrument,
+including certain derivative instruments embedded in other contracts, be
+recorded in the balance sheet as either an asset or liability measured at its
+fair value. The Company adopted SFAS 133 effective January 1, 2001. The
+cumulative effect of the accounting change, net of tax, recorded as other
+comprehensive loss was $3.8 million.
+50
+SFAS 133 requires the Company to report changes in the fair value of its
+derivative financial instruments that qualify as cash flow hedges in other
+comprehensive income, a component of stockholders' equity, until realized. See
+Note 6 for a discussion of the Company's derivative financial instruments.
+In June 2001, the FASB issued Statement of Financial Accounting Standards No.
+143, Accounting for Asset Retirement Obligations ("SFAS 143") effective for
+fiscal years beginning after June 15, 2002. SFAS 143 essentially requires
+entities to record the fair value of a liability for obligations associated with
+the retirement of tangible long-lived assets and the associated asset retirement
+costs. Callon adopted the statement on January 1, 2003 resulting in a cumulative
+effect of accounting change of $181,000, net of tax. See Note 8.
+In December 2002, the FASB issued Statement of Financial Accounting Standards
+No. 148 ("SFAS 148"), "Accounting for Stock-Based Compensation-Transition and
+Disclosure -an amendment of SFAS No. 123." SFAS 148 amends SFAS 123, "Accounting
+for Stock-Based Compensation", to provide alternative methods of transition for
+a voluntary change to the fair value based method of accounting for stock-based
+employee compensation. In addition, this statement amends the disclosure
+requirements of SFAS 123 to require disclosures in both annual and interim
+financial statements about the method of accounting for stock-based employee
+compensation and the effect of the method used on the reported results. SFAS 148
+was effective for the year ended December 31, 2002 and for interim financial
+statements commencing in 2003. The adoption of this pronouncement by the Company
+did not have an impact on its financial condition or results of operations. See
+Stock-Based Compensation for related disclosures.
+In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
+Variable Interest Entities, an Interpretation of Accounting Research Bulletin
+(ARB) 51" ("FIN 46"). FIN 46 addresses consolidation by business enterprises of
+variable interest entities ("VIEs"). The primary objective of FIN 46 is to
+provide guidance on the identification of, and financial reporting for, entities
+over which control is achieved through means other than voting rights; such
+entities are known as VIEs. The provisions of FIN 46 are effective immediately
+for these variable interest entities created after January 31, 2003. On December
+24, 2003, the FASB issued a revision to FIN 46 which among other things deferred
+the effective date for certain variable interests created prior to January 31,
+2003. Application is required for interests in special-purpose entities in the
+periods ending after December 15, 2003 and application is required for all other
+types of variable interest entities in the periods ending after March 31, 2004.
+The Company adopted FIN 46, as revised, as of December 31, 2003, which had no
+impact on the financial statements.
+In June 2001, the FASB issued Statement of Financial Accounting Standards No.
+141 ("SFAS 141"), "Business Combinations," which requires the use of the
+purchase method of accounting for business combinations initiated after June 30,
+2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also
+issued Statement of Financial Accounting Standards No. 142 ("SFAS 142"),
+"Goodwill and Other Intangible Assets," which discontinues the practice of
+amortizing goodwill and indefinite lived intangible assets and initiates an
+annual review of impairment. The new standard also requires that all intangible
+assets be aggregated and presented as a separate line item in the balance sheet.
+The adoption of SFAS No. 141 and 142 had no impact on the Company's financial
+position or results of operations. A reporting issue has arisen regarding the
+application of certain provisions of SFAS No. 141 and 142 to companies in the
+oil and gas industry. The issue is whether SFAS No. 141 requires registrants to
+classify the costs of mineral rights associated with extracting oil and gas as
+intangible assets in the balance sheet, apart from other capitalized oil and gas
+property costs, and provide specific footnote disclosures. Historically, the
+Company has included the costs of mineral rights associated with extracting oil
+and gas as
+51
+a component of oil and gas properties. These costs include those to acquire
+contract based drilling and mineral use rights such as delay rentals, lease
+bonuses, commissions and brokerage fees, and other leasehold costs.
+The Emerging Issues Task Force ("EITF") has added the treatment of oil and gas
+mineral rights to an upcoming agenda, which may result in a change in the
+classification of these amounts, as described above. The Company will continue
+to classify its oil and gas leasehold costs as tangible oil and gas properties
+until further guidance is provided. The Company's cash flows and results of
+operations would not be affected since such intangible assets would continue to
+be depleted and assessed for impairment in accordance with full cost accounting
+rules, as allowed by SFAS No. 142. Further, the Company believes that the
+amounts that would be classified as intangible assets as of December 31, 2003
+and 2002 would be immaterial.
+The Company follows the asset and liability method of accounting for deferred
+income taxes prescribed by Statement of Financial Accounting Standards No. 109
+("SFAS 109") "Accounting for Income Taxes". The statement provides for the
+recognition of a deferred tax asset for deductible temporary timing differences,
+capital and operating loss carryforwards, statutory depletion carryforward and
+tax credit carryforwards, net of a "valuation allowance". The valuation
+allowance is provided for that portion of the asset, for which it is deemed more
+likely than not, that it will not be realized. See Note 3.
+PROPERTY AND EQUIPMENT
+The Company follows the full cost method of accounting for oil and gas
+properties whereby all costs incurred in connection with the acquisition,
+exploration and development of oil and gas reserves, including certain overhead
+costs, are capitalized. Such amounts include the cost of drilling and equipping
+productive wells, dry hole costs, lease acquisition costs, delay rentals,
+interest capitalized on unevaluated leases and other costs related to
+exploration and development activities. Payroll and general and administrative
+costs capitalized include salaries and related fringe benefits paid to employees
+directly engaged in the acquisition, exploration and/or development of oil and
+gas properties as well as other directly identifiable general and administrative
+costs associated with such activities. Such capitalized costs ($13.2 million in
+2003, $9.6 million in 2002 and $10.0 million in 2001) do not include any costs
+related to production or general corporate overhead. Costs associated with
+unevaluated properties, including capitalized interest on such costs, are
+excluded from amortization. Unevaluated property costs are transferred to
+evaluated property costs at such time as wells are completed on the properties,
+the properties are sold or management determines that these costs have been
+impaired.
+Costs of properties, including future development and net future site
+restoration, dismantlement and abandonment costs, which have proved reserves and
+those which have been determined to be worthless, are depleted using the
+unit-of-production method based on proved reserves. If the total capitalized
+costs of oil and gas properties, net of accumulated amortization and deferred
+taxes relating to oil and gas properties, exceed the sum of (1) the estimated
+future net revenues from proved reserves at current prices and discounted at 10%
+and (2) the lower of cost or market of unevaluated properties (the full cost
+ceiling amount), net of tax effects, then such excess is charged to expense
+during the period in which the excess occurs. See Note 9.
+Upon the acquisition or discovery of oil and gas properties, management
+estimates the future net costs to be incurred to dismantle, abandon and restore
+the property using available geological, engineering and regulatory data. Such
+cost estimates are periodically updated for changes in conditions and
+requirements. Such estimated amounts are considered as part of the full cost
+pool subject to amortization upon acquisition
+52
+or discovery. Until January 1, 2003, such costs were capitalized as oil and gas
+properties as the actual restoration, dismantlement and abandonment activities
+took place. As discussed above under Accounting Pronouncements, beginning
+January 1, 2003, the Company changed the method for which we account for such
+costs upon adoption of SFAS 143 and these costs are included in the full cost
+pool. For purposes of the full cost ceiling test, the Company nets the Asset
+Retirement Obligation liability against the net capitalized costs of oil and gas
+properties and includes cash outflows associated with asset retirement
+obligations in the calculation of the full cost ceiling amount.
+Depreciation of other property and equipment is provided using the straight-line
+method over estimated lives of three to 20 years. Depreciation of pipeline and
+other facilities is provided using the straight-line method over estimated lives
+of 15 to 27 years.
+SALE OF PRODUCTION PAYMENT INTEREST
+In June 1999, the Company acquired a working interest in the Mobile Block 864
+Area where the Company already owned an interest. Concurrent with this
+acquisition, the seller received a volumetric production payment, valued at
+approximately $14.8 million, from production attributable to a portion of the
+Company's interest in the area over a 39-month period. The Company recorded a
+liability associated with the sale of this production payment interest because a
+substantial obligation for future performance existed. Under the terms of the
+sale, the Company was obligated to deliver the production volumes free and clear
+of royalties, lease operating expenses, production taxes and all capital costs.
+The production payment was amortized, beginning in June 1999, to oil and gas
+sales on the units-of-production method as associated hydrocarbons were
+delivered, and expired in July 2002.
+NATURAL GAS IMBALANCES
+The Company follows the entitlement method of accounting for its proportionate
+share of gas production on a well-by-well basis, recording a receivable to the
+extent that a well is in an "undertake" position and conversely recording a
+liability to the extent that a well is in an "overtake" position.
+DERIVATIVES
+The Company uses derivative financial instruments for price protection purposes
+on a limited amount of its future production and does not use them for trading
+purposes. Such derivatives are accounted for under SFAS 133 (See Note 6).
+ACCOUNTS RECEIVABLE
+Accounts receivable consists primarily of accrued oil and gas production
+receivables. The balance in the reserve for doubtful accounts included in
+accounts receivable was $103,000 and $143,000 at December 31, 2003 and 2002,
+respectively. Net charge offs were $40,000 in 2003 and net recoveries were
+$75,000 in 2002. There were no provisions to expense in the three-year period
+ended December 31, 2003.
+ACCOUNTS PAYABLE AND ACCRUED LIABILITIES TO BE REFINANCED
+These amounts included in the Consolidated Balance Sheet represent capital
+expenditures in accounts payable and accrued liabilities that were refinanced
+with the availability under the Company's senior secured credit facility
+subsequent to December 31, 2002. Amounts in 2003 were classified as short term
+because of the maturity of the Credit Facility on June 30, 2004.
+53
+STOCK-BASED COMPENSATION
+The Company's pro forma net income (loss) and net income (loss) per share of
+common stock for the 12-month periods ended December 31, 2003, 2002 and 2001 had
+compensation costs been recorded using the fair value method in accordance with
+SFAS 123, as amended by SFAS 148 are presented below pursuant to the disclosure
+requirements of SFAS 148 (in thousands except per share data):
+2003 2002 2001
+-------- ------- -------
+(IN THOUSANDS, EXCEPT PER SHARE DATA)
+Net income (loss) available to common shares,
+as reported $(19,268) $(2,948) $ 539
+Stock-based compensation expense included
+in net income as reported, net of tax 17 270 397
+Deduct: Total stock-based
+compensation expense under fair
+value based method, net of tax (202) (907) (1,775)
+-------- ------- -------
+Pro forma net income (loss) available to
+common shares $(19,453) $(3,585) $ (839)
+======== ======= =======
+Basic earnings (loss) per share: As Reported (1.41) (.22) .04
+Pro Forma (1.42) (.27) (.06)
+Diluted earnings (loss) per share: As Reported (1.41) (.22) .04
+Pro Forma (1.42) (.27) (.06)
+See Note 11 for descriptions and additional disclosures related to the plans.
+MAJOR CUSTOMERS
+The Company's production is sold generally on month-to-month contracts at
+prevailing prices. The following table identifies customers to whom it sold a
+significant percentage of its total oil and gas production during each of the
+12-month periods ended:
+DECEMBER 31,
+------------------
+2003 2002 2001
+---- ---- ----
+Petrocom Energy Group, Ltd. 4% 4% --
+Dynegy 5% 7% 8%
+Prior Energy Corporation 20% -- 20%
+Reliant Energy Services 28% 70% 49%
+Louis Dreyfus Energy Services 27% -- --
+Because alternative purchasers of oil and gas are readily available, the Company
+believes that the loss of any of these purchasers would not result in a material
+adverse effect on its ability to market future oil and gas production.
+STATEMENTS OF CASH FLOWS
+For purposes of the Consolidated Financial Statements, the Company considers all
+highly liquid investments purchased with an original maturity of three months or
+less to be cash equivalents.
+54
+The Company paid no federal income taxes for the three years ended December 31,
+2003. During the years ended December 31, 2003, 2002 and 2001, the Company made
+cash payments for interest of $27,913,000, $25,507,000 and $16,441,000,
+respectively.
+PER SHARE AMOUNTS
+Basic income or loss per common share was computed by dividing net income or
+loss by the weighted average number of shares of common stock outstanding during
+the year. Diluted income or loss per common share was determined on a weighted
+average basis using common shares issued and outstanding adjusted for the effect
+of stock options considered common stock equivalents computed using the treasury
+stock method and the effect of the convertible preferred stock (if dilutive).
+The conversion of the preferred stock was not included in any annual calculation
+due to its antidilutive effect on diluted income or loss per common share. In
+addition, below are the shares relating to stock options, warrants and
+restricted stock that were not included in diluted shares for the twelve-month
+periods ended December 31, 2003 and 2002 due to the fact that the Company had a
+loss for these periods. The Company had net income for the period ended December
+31, 2001 and therefore had no such shares for this period.
+TWELVE MONTHS ENDED DECEMBER 31,
+--------------------------------
+(IN THOUSANDS)
+2003 2002
+---- ----
+Stock options 63 13
+Warrants 424 372
+Restricted Stock 248 122
+A reconciliation of the basic and diluted per share computation is as follows
+(in thousands, except per share amounts):
+2003 2002 2001
+-------- ------- -------
+(a) Net income (loss) available to common shares $(19,268) $(2,948) $ 539
+Preferred dividends assuming conversion of
+preferred stock (if dilutive) -- -- --
+-------- ------- -------
+(b) Income (loss) available to common shares assum-
+ing conversion of preferred stock (if dilutive) $(19,268) $(2,948) $ 539
+======== ======= =======
+(c) Weighted average shares outstanding 13,662 13,387 13,273
+Dilutive impact of stock options -- -- 27
+Dilutive impact of restricted stock -- -- --
+Dilutive impact of warrants -- -- 66
+Convertible preferred stock (if dilutive) -- -- --
+-------- ------- -------
+(d) Total diluted shares 13,662 13,387 13,366
+======== ======= =======
+Stock options and warrants excluded due to the
+exercise price being greater than the stock price 2,297 2,250 1,438
+Basic income (loss) per share (a/c) $ (1.41) $ (.22) $ .04
+Diluted income (loss) per share (b/d) $ (1.41) $ (.22) $ .04
+55
+FAIR VALUE OF FINANCIAL INSTRUMENTS
+Fair value of cash, cash equivalents, accounts receivable, accounts payable, the
+capital lease and the senior secured credit facility approximates book value at
+December 31, 2003 and 2002. Fair value of long-term debt (specifically, the
+10.125%, the 10.25%, the 11% Senior Subordinated Notes and the 12% loans) have
+an estimated fair value of 100% of face value at December 31, 2003.
+3. INCOME TAXES
+The Company has recorded a deferred tax asset at December 31, 2003 and 2002 and
+a valuation allowance at December 31, 2003 as follows:
+DECEMBER 31,
+---------------------
+2003 2002
+-------- --------
+(IN THOUSANDS)
+Federal net operating loss carryforwards $ 61,805 $ 42,464
+Statutory depletion carryforward 4,255 4,251
+Temporary differences:
+Oil and gas properties (66,725) (39,159)
+Pipeline and other facilities -- (299)
+Non-oil and gas property (16) (30)
+Other 1,620 1,540
+SFAS 143-Asset Retirement Obligations 10,563 --
+-------- --------
+Total tax asset 11,502 8,767
+Valuation allowance (11,502) --
+-------- --------
+Net tax asset $ -- $ 8,767
+======== ========
+SFAS 109 provides for the weighing of positive and negative evidence in
+determining whether it is more likely than not that a deferred tax asset is
+recoverable. The Company has incurred losses in 2002 and 2003 and has losses on
+an aggregate basis for the three-year period ended December 31, 2003. However,
+as discussed in Note 5, in December 2003 the Company refinanced nearly all its
+highest cost debt, incurring an early extinguishment loss of $5.6 million, but
+achieving significant interest savings in the future. In addition, as discussed
+in Note 5, the first two of the Company's deepwater projects began production in
+November 2003, which is expected to result in a significant increase in 2004
+production as compared to 2003. Nevertheless, relevant accounting guidance
+suggests that a recent history of cumulative losses constitutes significant
+negative evidence, and that future expectations about income are overshadowed by
+such recent losses. As a result, the Company established a valuation allowance
+of $11.5 million as of December 31, 2003. If the Company achieves profitable
+operations in 2004, the Company expects it will reverse a portion of the
+valuation allowance in an amount at least sufficient to eliminate any tax
+provision in that period.
+56
+Below is a reconciliation of the reported amount of income tax expense
+attributable to continuing operations for the year to the amount of income tax
+expense that would result from applying domestic federal statutory tax rates to
+pretax income from continuing operations.
+YEAR ENDED DECEMBER 31,
+-----------------------
+2003 2002 2000
+---- ---- ----
+Income tax expense (benefit) computed at the statutory
+federal income tax rate (35%) (35%) 35%
+Change in valuation allowance 118% -- --
+Write off of NOL's 4% -- --
+---- ---- ----
+Effective income tax rate 87% (35%) 35%
+==== ==== ====
+The Company has significant state net operating loss carryforwards that are not
+included in the deferred tax asset above, as the Company does not anticipate
+generating taxable state income in the states in which these loss carryforwards
+apply. The Company has very limited state taxable income as primarily all of its
+revenue is generated in federal waters not subject to state income taxes.
+4. OTHER COMPREHENSIVE INCOME
+A recap of the Company's 2003, 2002 and 2001 comprehensive income (net of tax)
+is shown below (in thousands):
+YEARS ENDED DECEMBER 31,
+------------------------------
+2003 2002 2001
+-------- -------- --------
+Other comprehensive income (loss):
+Cumulative effect of change in
+accounting principle $ -- $ -- $ (3,764)
+Change in derivatives fair value 449 (469) 9,735
+Amortization of Enron derivatives -- (5,971) --
+-------- -------- --------
+Total other comprehensive income (loss) $ 449 $ (6,440) $ 5,971
+======== ======== ========
+57
+5. LONG-TERM DEBT
+Long-term debt consisted of the following at:
+DECEMBER 31,
+2003 2002
+--------- ---------
+(IN THOUSANDS)
+Senior Secured Credit Facility $ 30,000* $ 65,000
+Senior Subordinated Notes (due 2004) - these notes were
+retired with restricted cash on 01/08/2004:
+10.125% notes net of discount 21,772* 20,086
+10.250% notes 40,000* 40,000
+12% Senior Loans (due 2005) net of discount 9,490 87,020
+11% Senior Subordinated Notes (due 2005) 33,000 33,000
+9.75% Senior Loans (due 2010) net of discount 170,684 --
+Capital Lease 3,162 4,483
+--------- ---------
+Total Long-term Debt 308,108* 249,589
+Less current portion 93,223* 1,320
+--------- ---------
+Long-term portion $214,885 $248,269
+========= =========
+* $62.9 million of 2004 senior subordinated notes are in this
+current portion and were retired on January 8, 2004. Total Long-term
+Debt after retirement of the 2004 notes was $245.2 million. The
+senior secured credit facility comprises $30 million of the current
+portion. It is expected that the maturity date of the facility will
+be renegotiated and extended or the facility will be replaced.
+SENIOR SECURED CREDIT FACILITY. The Company negotiated its senior secured credit
+facility effective October 31, 2000 with Wachovia Bank, National Association,
+formerly First Union National Bank. Borrowings under the senior secured credit
+facility are secured by mortgages covering substantially all of the Company's
+producing oil and gas properties. On June 30, 2002 the Company amended the
+senior secured credit facility to increase availability under the revolving
+borrowing base from $50 million to $75 million under a dual tranche loan. The
+Tranche A revolver bears interest at 0.25% to 0.75% above a defined base rate
+depending on utilization of the borrowing base or, at the option of the Company,
+LIBOR plus 2% to 2.5% based on utilization of the borrowing base and has a
+maximum aggregate credit amount of $45 million until Tranche B is retired. The
+range of interest rates on the Tranche A revolver was 3.12% to 5.00% for the 12
+months ended December 31, 2003. The Tranche B part of the facility bears an
+interest rate of 15% and has an aggregate maximum credit amount of $30 million.
+The weighted average interest rate for the senior secured credit facility debt
+outstanding at December 31, 2003 and 2002 was 15% and 9%, respectively. Under
+the senior secured credit facility, a commitment fee of 0.25% or 0.375% per
+annum, depending on the amount of the unused portion of the borrowing base, is
+payable quarterly.
+There were no borrowings outstanding on Tranche A and there was $30 million
+outstanding against Tranche B at December 31, 2003. On December 21, 2003, the
+Company exercised its right to call the Tranche B loan with a 30-day notice and
+on January 21, 2004, the Company drew $27 million under Tranche A and redeemed
+the Tranche B principal plus a 1% call premium. Repayment of Tranche B cancelled
+any future credit amounts available under Tranche B. Currently, the facility
+provides for a $45.0 million borrowing base under Tranche A which is adjusted
+periodically on the basis of the discounted present value of future net cash
+flows attributable to our proved producing oil and gas reserves
+58
+and other factors deemed relevant by the lenders. The borrowing base for Tranche
+A is currently being reviewed by the lenders and could be increased due to the
+Company's proved producing reserves increasing as a result of the Medusa and
+Habanero fields commencing production in the fourth quarter of 2003. This
+facility expires on June 30, 2004 and the Company is currently reviewing options
+to extend the maturity date or to replace the facility with one that is similar
+or with more favorable terms. Borrowings under the credit facility are
+classified as current at December 31, 2003.
+SENIOR SUBORDINATED NOTES (DUE 2004). Covenant defeasance was exercised under
+the indentures for the 10.125% and 10.25% notes on December 8, 2003 and a
+required 30-day redemption notice was distributed to holders. The funds
+necessary to redeem the notes were placed in trust, from the net proceeds of the
+new 9.75% loans and the trustee paid the holders of the notes on January 8,
+2004. The terms of the covenant defeasance that were exercised did not meet the
+requirements for legal defeasance under SFAS 140, "Accounting for Transfers and
+Servicing of Financial Instruments and Extinguishment of Debt", and therefore
+these notes are considered outstanding at December 31, 2003. The funds in trust
+were classified on the Company's December 31, 2003 consolidated balance sheet as
+restricted cash.
+On September 15, 2002, $36 million of the Company's 10.125% Senior Subordinated
+Notes ("Notes") that were issued on July 31, 1997, were due. The holders of
+$22.9 million of the Notes consented to an extension of such Notes until July
+31, 2004. The Company granted 274,980 warrants (with a fair market value of
+approximately $1.3 million) to purchase Common Stock of the Company and paid
+consent fees in the amount of $2.3 million to the holders of the Notes that
+granted the extensions. These amounts were treated as an additional discount on
+the debt. The warrants have a term of five years and an exercise price of $0.01.
+The holders of the Notes had exercised approximately 116,000 warrants as of
+December 31, 2003. The holders of the Notes that did not consent to the
+extension were paid on the maturity date in September 2002. Interest on the
+Notes was payable quarterly, on March 15, June 15, September 15, and December 15
+of each year.
+The Company accounted for the extension of the $22.9 million in Notes described
+above as an extinguishment of the Notes and the issuance of new securities were
+recorded at a fair value of $19.3 million. The net loss on extinguishment was
+not significant. Costs deferred with the extensions were being amortized through
+July 2004. As a result of the redemption of the Notes on January 8, 2004, the
+unamortized balance of the discount and the deferred costs of $1.1 million will
+be expensed during the first quarter of 2004 as a loss on early extinguishment
+of debt.
+On July 15, 1999, the Company completed the sale of $40 million of Senior
+Subordinated Notes due 2004 at 10.25%. These notes were not entitled to any
+mandatory sinking fund payments and were subject to redemption at the Company's
+option at par plus unpaid interest at any time after March 15, 2001. Interest
+was paid quarterly. The notes were redeemed on January 8, 2004. These notes are
+classified as current at December 31, 2003.
+12% SENIOR UNSECURED CREDIT FACILITY (DUE 2005). In July 2001, the Company
+entered into a $95 million senior unsecured credit facility with a private
+lender. The Company borrowed $45 million upon closing of the loan and borrowed
+the remaining $50 million in December 2001. The loans bear interest at the rate
+of 12% per year. Under the terms of the agreement, Callon also issued warrants
+to purchase, at a nominal exercise price, 265,210 shares of its Common Stock
+(fair value of $3.1 million) and conveyed an overriding royalty interest equal
+to 2% of the Company's net interest in four existing deepwater discoveries (fair
+value of $5.9 million). These amounts were treated as an additional discount on
+the debt. The warrants and the overriding royalty interest were earned by the
+lender based on the ratio of the
+59
+amount of the loan proceeds advanced to the total loan facility amount. The
+loans will mature March 31, 2005 and have an effective interest rate of
+approximately 16%.
+The Company recorded these borrowings at a value of $84 million net of discount.
+Deferred costs associated with the loans are being amortized through March 2005.
+Upon redemption of $85 million of the loans on December 30, 2003 the pro rata
+portion of the unamortized balance of the discount and the associated deferred
+costs in the amount of $4.4 million and a 1% call premium of $850,000 were
+expensed during the fourth quarter of 2003 as a loss on early extinguishment of
+debt.
+11% SENIOR SUBORDINATED NOTES (DUE 2005). On October 26, 2000 the Company
+completed the sale of $33 million of 11% Senior Subordinated Notes due December
+15, 2005. The Company netted $31.5 million from the offering after deducting the
+underwriters' discount and offering expenses.
+9.75% SENIOR LOANS (DUE 2010). In December 2003 the Company borrowed $185
+million pursuant to a senior unsecured credit facility. The loans under the
+credit facility have a stated interest rate of 9.75% and a seven-year maturity.
+The net proceeds of $181.3 million were used to redeem $22.9 million of 10.125%
+senior subordinated notes due July 31, 2004, $40 million of 10.25% senior
+subordinated notes due September 15, 2004 and $85 million of our 12% loan due
+March 31, 2005 issued pursuant to a senior unsecured credit agreement dated July
+29, 2001 plus a 1% pre-payment premium of $850,000, and to reduce the balance
+outstanding under the Company's senior secured credit facility. In conjunction
+with the new senior unsecured notes, the Company issued detachable warrants to
+purchase 2.775 million of our common stock at an exercise price of $10 per
+share. The warrants were valued at $10.6 million and were treated as an
+additional discount on the debt. This senior unsecured debt matures December 8,
+2010 and has an effective interest rate of 11.4%. The Company recorded the
+issuance of these new securities at a fair value of $171 million. Deferred costs
+of $14 million associated with the notes will be amortized over the life of the
+notes.
+REMAINING MATURITIES FOR UNSECURED DEBT. Our remaining maturities for unsecured
+debt consist of the $185 million in 9.75% loans due 2010, $10 million of the 12%
+loans with a due date of March 31, 2005 and $33 million of 11% senior
+subordinated notes with a due date of December 15, 2005. These 2005 maturities
+will be retired by our primary sources of capital which are cash flows from
+operations, borrowings from financial institutions and the sale of debt and
+equity securities.
+CAPITAL LEASE. In December 2001, the Company entered into a 10-year gas
+processing agreement associated with a production facility on Callon's Mobile
+Block 952 field with Hanover Compression Limited Partnership, which is being
+accounted for as a capital lease. Total minimum obligations are $8.4 million
+with interest representing approximately $2.8 million and the present value
+minimum obligations were $5.6 million ($1.2 million current).
+RESTRICTIVE COVENANTS. The senior secured credit facility, the senior
+subordinated debt and the senior unsecured credit facilities contain various
+covenants including restrictions on additional indebtedness and payment of cash
+dividends as well as maintenance of certain financial ratios. The Company was in
+compliance with these covenants at December 31, 2003.
+60
+FUTURE MINIMUM LEASE PAYMENTS AND DEBT MATURITIES (IN THOUSANDS) ARE AS FOLLOWS:
+CAPITAL LEASE
+YEAR PAYMENTS DEBT
+---- -------- ----
+2004 $1,890 $ 92,915*
+2005 822 43,000
+2006 439 --
+2007 348 --
+2008 228 --
+Thereafter 694 185,000
+* These maturities consist of $62.9 million of senior subordinated notes which
+were retired on January 8, 2004 and $30 million under the senior secured credit
+facility which matures June 30, 2004 and which the Company expects will be
+renegotiated and extended or replaced with a new facility.
+6. DERIVATIVES
+The Company periodically uses derivative financial instruments to manage oil and
+gas price risk. Settlements of gains and losses on commodity price contracts are
+generally based upon the difference between the contract price or prices
+specified in the derivative instrument and a NYMEX price or other cash or
+futures index price.
+In 2003 and 2002, the Company purchased and sold various put options and call
+options and elected not to designate these derivative financial instruments as
+hedges and accordingly, the changes in fair value of these contracts were
+recorded through earnings. A loss of approximately $666,000 and $708,000 was
+recognized for the twelve month periods ended December 31, 2003 and 2002,
+respectively. The fair value of the open contracts at December 31, 2003 was a
+current liability of $134,640. At December 31, 2002 the fair value was a current
+asset of $352,500.
+During 2002, the Company entered into costless natural gas collar contracts in
+effect for February 2003 through October 2003. These agreements were for volumes
+of 275,000 Mcf per month with an average ceiling price of $4.79 and a floor
+price of $3.52. These contracts were accounted for as cash flow hedges under
+SFAS 133. The fair value of these collar contracts at December 31, 2002 was
+recorded on the balance sheet as a liability of $721,350. The Company recognized
+a reduction of $2,932,000 in oil and gas sales related to the settlements of
+such collars for the 12 months ended December 31, 2003.
+During 2003, the Company entered into additional costless natural gas collar
+contracts in effect for May 2003 through October 2003. These agreements were for
+volumes of 200,000 Mcf per month with a ceiling price of $5.80 and a floor price
+of $5.00. The Company elected not to designate these derivative financial
+instruments as hedges and accordingly, the changes in fair value of these
+contracts were recorded through earnings. For the twelve month period ended
+December 31, 2003, the Company recognized a gain of approximately $131,600.
+In 2001, the Company entered into derivative contracts for 2002 production with
+Enron North America Corp. ("Enron"). In the fourth quarter of 2001, the Company
+charged to expense (non-cash) $9.2 million representing the fair market value of
+these derivatives as of September 30, 2001. As the contracts matured, the
+Company recorded non-cash revenue each month. For the twelve month period ended
+December 31, 2002, the Company recorded approximately $9.2 million, as non-cash
+oil and gas revenues.
+61
+Also, in the second quarter of 2002, the Company completed the sale of its
+claims against Enron for $2.5 million and reported a pre-tax gain of that
+amount.
+In the fourth quarter of 2003, Callon entered into two natural gas collar
+contracts which are listed below:
+Collars
+Volumes per Quantity Floor Ceiling
+Product Month Type Price Price Period
+----------- ----------- -------- ------- ------- ----------
+Natural Gas 100,000 MMBtu $ 5.25 $7.25 12/03-03/04
+Natural Gas 100,000 MMBtu $ 5.00 $7.20 01/04-03/04
+These contracts are accounted for as cash flow hedges under SFAS 133. The
+Company recognized an increase of $52,500 in oil and gas sales related to the
+settlements of such collars in the twelve month period ended December 31, 2003.
+The fair value of these collar contracts at December 31, 2003 was recorded on
+the balance sheet as a liability in the amount of $30,400.
+In the first quarter of 2004, Callon entered into various derivative contracts
+which are listed in the table below:
+Swaps
+Volumes per Quantity
+Product Month Type Average Period
+--------- ----------- -------- --------- -----------
+Oil 30,000 Bbls $ 31.29 02/04-01/05
+Oil 15,000 Bbls $ 30.00 04/04-03/05
+Oil 15,000 Bbls $ 30.00 07/04-12/04
+Collars
+Average Average
+Volumes per Quantity Floor Ceiling
+Product Month Type Price Price Period
+----------- ----------- -------- --------- -------- -----------
+Oil 45,000 Bbls $ 29.33 $ 32.17 02/04-01/05
+Oil 15,000 Bbls $ 30.00 $ 32.50 02/04-10/04
+Natural Gas 500,000 MMBtu $ 5.00 $ 6.08 04/04-11/04
+Natural Gas 100,000 MMBtu $ 5.00 $ 5.60 06/04-11/04
+Natural Gas 300,000 MMBtu $ 5.00 $ 6.91 12/04-03/05
+These contracts will be accounted for as cash flow hedges under SFAS 133.
+7. COMMITMENTS AND CONTINGENCIES
+As described in Note 10, abandonment trusts (the "Trusts") have been established
+for future abandonment obligations of those oil and gas properties of the
+Company burdened by a net profits interest. The management of the Company
+believes the Trusts will be sufficient to offset those future abandonment
+liabilities; however, the Company is responsible for any abandonment expenses in
+excess of the Trusts' balances. As of December 31, 2003, total estimated site
+restoration, dismantlement and abandonment costs were approximately $7.4
+million, net of expected salvage value. Substantially all such costs are
+expected to be funded through the Trusts' funds, all of which will be accessible
+to the Company when abandonment work begins. In addition, as a working interest
+owner and/or operator of oil and gas properties, the Company is responsible for
+the cost of abandonment of such properties. See Notes 2 and 8.
+62
+From time to time, the Company, as part of the Consolidation and other capital
+transactions, entered into registration rights agreements whereby certain
+parties to the transactions are entitled to require the Company to register
+common stock of the Company owned by them with the Securities and Exchange
+Commission for sale to the public in firm commitment public offerings and
+generally to include shares owned by them, at no cost, in registration
+statements filed by the Company. Costs of the offering will not include broker's
+discounts and commissions, which will be paid by the respective sellers of the
+common stock.
+The Company is involved in various claims and lawsuits incidental to its
+business. In the opinion of management, the ultimate liability thereunder, if
+any, will not have a material adverse effect on the financial position or
+results of operations of the Company.
+The Company may be required to retroactively pay royalties to the Minerals
+Management Service on one of the Company's properties which could reduce
+revenues and reserves. The Company's Medusa deepwater property is eligible for
+royalty suspensions pursuant to the Deep Water Royalty Relief Act. However, the
+federal offshore leases covering this property contains "price threshold"
+provisions for oil and gas prices. Under this "price threshold" provision, if
+the average monthly New York Mercantile Exchange (NYMEX) sales price for oil or
+gas during a fiscal year exceeds the price threshold for oil or gas,
+respectively, then royalties on the associated production must be paid to the
+Minerals Management Service (MMS) at the rate stipulated in the lease. The price
+thresholds are adjusted annually by the implicit price deflator for the GDP. The
+determination of whether or not royalties are due as a result of the average
+NYMEX price exceeding the price threshold is made during the first quarter of
+the succeeding year. Any royalty payments due must be made shortly after this
+determination is made. If a royalty payment is due for all production during a
+year as a result of exceeding the price threshold, the lessee is required to
+make monthly royalty payments during the succeeding fiscal year for the
+succeeding year's production. If at the end of any year the average NYMEX price
+is below the price threshold, the lessee can apply for a refund for any
+associated royalties paid during that year and the lessee will not be required
+to pay royalties monthly during the succeeding year for the succeeding year's
+production.
+The thresholds and the average NYMEX prices are calculated by the MMS. The
+average NYMEX price for 2003 was $31.08 per barrel of oil and $5.49 per MMBtu of
+natural gas. For the year ended December 31, 2003 the thresholds were $32.77 per
+barrel of oil and $4.10 per MMBtu of natural gas, subject to finalization of the
+adjustment for the 2003 GDP implicit price deflator. As a result the Company
+will pay royalties related to 2003 gas production for Medusa, which commenced
+production in late November 2003 and will make monthly royalty payments for 2004
+gas production during 2004. The actual liability for 2004 oil royalties, if any,
+cannot be determined until after the end of 2004.
+In the year succeeding the year in which any of the Company's properties became
+subject to royalties as the result of the average NYMEX price exceeding the
+price threshold, the portion of reserves attributable to potential future
+royalties would not be included in a year-end reserve report. However, if the
+average NYMEX prices were below the price thresholds in subsequent years, our
+reserves would be increased to reflect reserves previously attributed to future
+royalties. As a result, reported oil and gas reserves could materially increase
+or decrease, depending on the relation of price thresholds versus the average
+NYMEX prices. The reduction in revenues resulting from an obligation to pay
+these royalties and subsequent reduction of proved reserves could have a
+material adverse effect on the Company's results of operations and financial
+condition. The Company's reserve report as of December 31, 2003 excluded gas
+reserves for Medusa that are subject to MMS royalties as a result of the average
+2003 NYMEX price for gas exceeding the price threshold. Oil reserves in this
+reserve report were not impacted since the 2003 average NYMEX price was below
+the threshold.
+63
+The Company's activities are subject to federal, state and local laws and
+regulations governing environmental quality and pollution control. Although no
+assurances can be made, the Company believes that, absent the occurrence of an
+extraordinary event, compliance with existing federal, state and local laws,
+rules and regulating the release of materials in the environment or otherwise
+relating to the protection of the environment will not have a material effect
+upon the capital expenditures, earnings or the competitive position of the
+Company with respect to its existing assets and operations. The Company cannot
+predict what effect additional regulation or legislation, enforcement polices
+thereunder, and claims for damages to property, employees, other persons and the
+environment resulting from the Company's operations could have on its
+activities.
+8. ASSET RETIREMENT OBLIGATIONS
+As discussed in Note 2, the Company adopted SFAS 143 on January 1, 2003. The
+impact of adopting the statement resulted in a gain of $181,000, net of tax,
+which is reported as a cumulative effect of change in accounting principle.
+Approximately $30.3 million was recorded as the present value of asset
+retirement obligations on January 1, 2003 with the adoption of SFAS 143 related
+to the Company's oil and gas properties. Interest is accreted on this amount and
+reported as accretion expense in the Consolidated Statements of Operations.
+Assets, primarily short-term U.S. Government securities, of approximately $7.4
+million at December 31, 2003, are recorded as restricted investments. These
+assets are held in abandonment trusts dedicated to pay future abandonment costs
+of oil and gas properties in which the Company has sold a net profits interest.
+If there is any excess of trust assets over abandonment costs, the excess will
+be distributed to the net profits interest owners.
+The following table summarizes the activity for the Company's asset retirement
+obligation:
+TWELVE MONTHS ENDED
+DECEMBER 31, 2003
+-------------------
+Asset retirement obligation at beginning of period $ --
+Liability recognized in transition 30,251
+Accretion expense 2,884
+Net profits interest accretion 371
+Liabilities incurred 3,649
+Liabilities settled (2,847)
+Revisions to estimate (617)
+-------
+Asset retirement obligation at end of period 33,691
+Less: current retirement obligation (8,571)
+-------
+Long-term retirement obligation $25,120
+=======
+Pro forma net income and earnings per share are not presented for the 12 months
+ended December 31, 2002 or 2001 because the pro forma application of SFAS 143 to
+the prior periods would not result in pro forma net income and earnings per
+share materially different from the actual amounts reported for the periods in
+the accompanying Consolidated Statements of Operations.
+64
+9. OIL AND GAS PROPERTIES
+The following table discloses certain financial data relating to the Company's
+oil and gas activities, all of which are located in the United States.
+YEARS ENDED DECEMBER 31,
+----------------------------------------
+2003 2002 2001
+--------- --------- ---------
+(IN THOUSANDS)
+Capitalized costs incurred:
+Evaluated Properties-
+Beginning of period balance $ 762,918 $ 704,937 $ 589,549
+Property acquisition costs 1,154 1,471 1,713
+Exploration costs 21,390 17,851 85,782
+Development costs 33,972 43,151 34,980
+SFAS 143-Asset Retirement Obligation 18,002 -- --
+Medusa Spar transaction (33,542) -- --
+Sale of mineral interests (982) (4,492) (7,087)
+--------- --------- ---------
+End of period balance $ 802,912 $ 762,918 $ 704,937
+========= ========= =========
+Unevaluated Properties (excluded from
+amortization) -
+Beginning of period balance $ 40,997 $ 37,560 $ 47,653
+Additions 5,228 5,802 8,760
+Capitalized interest 4,862 5,289 4,879
+Transfers to evaluated (16,836) (7,654) (23,732)
+--------- --------- ---------
+End of period balance $ 34,251 $ 40,997 $ 37,560
+========= ========= =========
+Accumulated depreciation, depletion
+and amortization-
+Beginning of period balance $ 426,254 $ 399,339 $ 378,589
+Provision charged to expense 28,195 26,915 20,750
+Cumulative effect of change in accounting
+principle (7,449) -- --
+--------- --------- ---------
+End of period balance $ 447,000 $ 426,254 $ 399,339
+========= ========= =========
+Unevaluated property costs, primarily lease acquisition costs incurred at
+federal lease sales, unevaluated drilling costs, capitalized interest and
+general and administrative costs being excluded from the amortizable evaluated
+property base, consisted of $8.6 million incurred in 2003, $7.1 million incurred
+in 2002 and $18.5 million incurred in 2001 and prior. These costs are directly
+related to the acquisition and evaluation of unproved properties and major
+development projects. The excluded costs and related reserves are included in
+the amortization base as the properties are evaluated and proved reserves are
+established or impairment is determined. The Company expects that the majority
+of these costs will be evaluated over the next three to five-year period.
+Depletion per unit-of-production (thousand cubic feet of gas equivalent)
+amounted to $2.03, $1.73 and $1.37 for the years ended December 31, 2003, 2002,
+and 2001, respectively.
+Under the full-cost accounting rules of the SEC, the Company reviews the
+carrying value of its proved oil and gas properties each quarter. Under these
+rules, capitalized costs of proved oil and gas properties net of accumulated
+depreciation, depletion and amortization (DD&A) and deferred income taxes, may
+not exceed the present value of estimated future net cash flows from proved oil
+and gas reserves, discounted at 10
+65
+percent, plus the lower of cost or fair value of unproved properties included in
+the costs being amortized, net of related tax effects. These rules generally
+require pricing future oil and gas production at the unescalated market price
+for oil and gas at the end of each fiscal quarter and require a write-down if
+the "ceiling" is exceeded, unless prices recover sufficiently before the date of
+the auditor's report. Given the volatility of oil and gas prices, it is
+reasonably possible that the Company's estimate of discounted future net cash
+flows from proved oil and gas reserves could change in the near term. If oil and
+gas prices decline significantly, even if only for a short period of time, it is
+possible that writedowns of oil and gas properties could occur in the future.
+See Note 13 for information regarding the SEC inquiries concerning the Company's
+proved reserves.
+10. NET PROFITS INTEREST
+From 1989 through 1994, the Constituent Entities entered into separate
+agreements to purchase certain oil and gas properties with gross contract
+acquisition prices of $170,000,000 ($150,000,000 net as of closing dates) and in
+simultaneous transactions, entered into agreements to sell overriding royalty
+interests ("ORRI") in the acquired properties. These ORRI are in the form of net
+profits interests ("NPI") equal to a significant percentage of the excess of
+gross proceeds over production costs, as defined, from the acquired oil and gas
+properties. A net deficit incurred in any month can be carried forward to
+subsequent months until such deficit is fully recovered. The Company has the
+right to abandon the purchased oil and gas properties if it deems the properties
+to be uneconomical.
+The Company has, pursuant to the purchase agreements, created abandonment trusts
+(see Note 7) whereby funds are provided out of gross production proceeds from
+the properties for the estimated amount of future abandonment obligations
+related to the working interests owned by the Company. The Trusts are
+administered by unrelated third party trustees for the benefit of the Company's
+working interest in each property. The Trust agreements limit disbursement of
+funds to the satisfaction of abandonment obligations. Any funds remaining in the
+Trusts after all restoration, dismantlement and abandonment obligations have
+been met will be distributed to the owners of the properties in the same ratio
+as contributions to the Trusts. Estimated future revenues and costs associated
+with the NPI and the Trusts are also excluded from the oil and gas reserve
+disclosures at Note 13. As of December 31, 2003 and 2002, the Trusts' assets
+(all cash and investments) totaled $7,420,000 and $6,896,000 respectively, all
+of which will be available to the Company to pay its portion, as working
+interest owner, of the restoration, dismantlement and abandonment costs
+discussed at Note 7. SFAS 143, discussed in Note 2 and 8, does not allow the
+Abandonment Trusts' assets to be used to offset the associated abandonment
+liability. The Company did not record any income or loss associated with the
+Trust asset or abandonment liability as a result of adoption of SFAS 143.
+At the time of acquisition of properties by the Company, the property owners
+estimated the future costs to be incurred for site restoration, dismantlement
+and abandonment, net of salvage value. A portion of the amounts necessary to pay
+such estimated costs was deposited in the Trusts upon acquisition of the
+properties, and the remainder is deposited from time to time out of the proceeds
+from production. The determination of the amount deposited upon the acquisition
+of the properties and the amount to be deposited as proceeds from production was
+based on numerous factors, including the estimated reserves of the properties.
+As operator, the Company receives all of the revenues and incurs all of the
+production costs for the purchased oil and gas properties but retains only that
+portion applicable to its net ownership share. As a result, the payables and
+receivables associated with operating the properties included in the Company's
+Consolidated Balance Sheets include both the Company's and all other outside
+owners' shares. However,
+66
+revenues and production costs associated with the acquired properties reflected
+in the accompanying Consolidated Statements of Operations represent only the
+Company's share, after reduction for the NPI.
+11. EMPLOYEE BENEFIT PLANS
+The Company has adopted a series of incentive compensation plans designed to
+align the interest of the executives and employees with those of its
+stockholders. The following is a brief description of each plan:
+The Savings and Protection Plan provides employees with the option to
+defer receipt of a portion of their compensation and the Company may, at
+its discretion, match a portion of the employee's deferral with cash and
+Company Common Stock. The Company may also elect, at its discretion, to
+contribute a non-matching amount in cash and Company Common Stock to
+employees. The amounts held under the Savings and Protection Plan are
+invested in various funds maintained by a third party in accordance with
+the directions of each employee. An employee is fully vested, including
+Company discretionary contributions, immediately upon participation in the
+Savings and Protection Plan. The total amounts contributed by the Company,
+including the value of the common stock contributed, were $562,000,
+$611,000 and $595,000 in the years 2003, 2002 and 2001, respectively.
+The 1994 Stock Incentive Plan (the "1994 Plan"), approved by the
+shareholders in 1994, provides for 600,000 shares of Common Stock to be
+reserved for issuance pursuant to such plan. Under the 1994 Plan, the
+Company may grant both stock options qualifying under Section 422 of the
+Internal Revenue Code and options that are not qualified as incentive
+stock options, as well as performance shares. These options have an
+expiration date of 10 years from the date of grant.
+On August 23, 1996, the Board of Directors of the Company approved and
+adopted the Callon Petroleum Company 1996 Stock Incentive Plan (the "1996
+Plan"). The 1996 Plan was approved by the shareholders in 1997 and
+provides for the same types of awards as the 1994 Plan and is limited to a
+maximum of 1,200,000 shares (as amended from the original 900,000 shares)
+of common stock that may be subject to outstanding awards. Unvested
+options are subject to forfeiture upon certain termination of employment
+events and expire 10 years from the date of grant.
+The Company granted 533,000 stock options to employees on March 23, 2000
+and 120,000 stock options to directors on July 25, 2000 at $10.50 per
+share. The March 23, 2000 grant was subject to shareholder approval of an
+amendment to the 1996 Stock Incentive Plan. The amendment, which was
+approved on May 9, 2000 at the Annual Meeting of Shareholders, increased
+the number of shares reserved for issuance under the 1996 plan to
+2,200,000 shares. The excess of the market price over the exercise price
+on the approval date of the amendment is amortized over the three-year
+vesting period of the options. Compensation costs of $27,000, $416,000 and
+$611,000 were recognized in 2003, 2002 and 2001, respectively, related to
+these options.
+On February 14, 2002, the Board of Directors of the Company approved and
+adopted the 2002 Stock Incentive Plan (the "2002 Plan"). Pursuant to the
+2002 Plan, 350,000 shares of common stock shall be reserved for issuance
+upon the exercise of options or for grants of stock options, stock
+appreciation rights or units, bonus stock, or performance shares or units.
+This Plan qualified as a "broadly based" plan under the provisions of the
+New York Stock
+67
+Exchange's rules and regulations and therefore did not require shareholder
+approval. Because the 2002 Plan is a broadly based plan, the aggregate
+number of shares underlying awards granted to officers and directors
+cannot exceed 50% of the total number of shares underlying the awards
+granted to all employees during any three-year period.
+In 2002, the Company awarded 300,000 shares of restricted stock from the
+1996 and the 2002 Plan and 70,500 from treasury shares to be issued as
+vested. The issuance of the restricted stock using treasury shares did not
+require shareholder approval pursuant to the New York Stock Exchange's
+rules and regulations, and therefore shareholder approval was not sought.
+These shares will generally vest to the recipients over a three-year
+period (one-third in each year) beginning in November 2002. The deferred
+compensation portion of this grant will be amortized to expense over the
+vesting period. The non-cash amortization expense in, 2003 and 2002 was
+$454,000 and $496,000, respectively.
+In 1997, the Board of Directors authorized the implementation of the
+Callon Petroleum Company 1997 Employee Stock Purchase Plan (the "1997
+Purchase Plan"), which was approved by the Company's shareholders at the
+1997 Annual Meeting. The Plan provides eligible employees of the Company
+with the opportunity to acquire a proprietary interest in the Company
+through participation in a payroll deduction-based employee stock purchase
+plan. An aggregate of 250,000 shares of common stock have been reserved
+for issuance over the 10-year term of the 1997 Purchase Plan. The purchase
+price per share at which common stock will be purchased on the
+participant's behalf on each purchase date within an offering period is
+equal to 85 percent of the fair market value per share of common stock.
+A summary of the status of the Company's stock option plans for the three most
+recent years and changes during the years then ended is presented in the table
+and narrative below:
+2003 2002 2001
+--------------------- ---------------------- ----------------------
+WTD AVG WTD AVG WTD AVG
+SHARES EX PRICE SHARES EX PRICE SHARES EX PRICE
+---------- -------- ---------- --------- ---------- --------
+Outstanding, beginning of year 2,520,417 $ 9.90 2,332,667 $ 10.84 2,304,167 $ 10.83
+Granted (at market) 30,000 5.12 310,000 4.45 30,000 11.61
+Exercised (500) 4.10 -- -- (1,500) 9.00
+Forfeited (99,050) 9.74 (122,250) 14.10 -- --
+Expired -- -- -- -- -- --
+---------- -------- ---------- ------- ---------- -------
+Outstanding, end of year 2,450,867 $ 9.84 2,520,417 $ 9.90 2,332,667 $ 10.84
+========== ======== ========== ======= ========== =======
+Exercisable, end of year 2,262,067 $ 10.31 2,224,334 $ 10.57 2,057,977 $ 10.80
+========== ======== ========== ======= ========== =======
+Weighted average fair value of
+options granted (at market) $ 2.97 $ 2.44 $ 5.80
+========== ========== ==========
+68
+The following table sets forth additional information regarding options
+outstanding at December 31, 2003. Contractual life and exercise prices represent
+weighted averages for options outstanding and options exercisable.
+Options Outstanding Options Exercisable
+------------------------------------- ----------------------
+Range of Number Contractual Exercise Number Exercise
+exercise prices Outstanding Life (years) Price Exercisable Price
+------------------ ----------- ------------ -------- ----------- --------
+$ 3.70 to $ 6.41 315,200 8.6 $ 4.47 126,400 $ 4.74
+$ 9.00 to $ 12.28 2,070,667 3.9 $ 10.53 2,070,667 $ 10.53
+$ 13.56 to $ 15.31 65,000 4.3 $ 14.16 65,000 $ 14.16
+The fair value of each option grant is estimated on the date of grant using the
+Black-Scholes option pricing model with the following weighted average
+assumptions used for options granted during the years presented are as follows:
+2003 2002 2001
+------ ------ ------
+Risk free interest rate 4.0% 3.7% 4.5%
+Expected life (years) 5.0 5.0 5.0
+Expected volatility 65.3% 61.0% 43.9%
+Expected dividends -- -- --
+12. EQUITY TRANSACTIONS
+In November 1995, the Company sold 1,315,500 shares of $2.125 Convertible
+Exchangeable Preferred Stock, Series A (the "Preferred Stock") for net proceeds
+of $30.9 million. Annual dividends are $2.125 per share and are cumulative. The
+net proceeds of the $.01 par value stock after underwriters discount and expense
+was $30,899,000. Each share has a liquidation preference of $25.00, plus accrued
+and unpaid dividends. Dividends on the Preferred Stock are cumulative from the
+date of issuance and are payable quarterly, commencing January 15, 1996. The
+Preferred Stock is convertible at any time, at the option of the holders
+thereof, unless previously redeemed, into shares of Common Stock of the Company
+at an initial conversion price of $11 per share of Common Stock, subject to
+adjustments under certain conditions.
+The Preferred Stock is redeemable at any time on or after December 31, 1998, in
+whole or in part at the option of the Company at a redemption price of $26.488
+per share beginning at December 31, 1998 and at premiums declining to the $25.00
+liquidation preference by the year 2005 and thereafter, plus accrued and unpaid
+dividends. The Preferred Stock is also exchangeable, in whole, but not in part,
+at the option of the Company on or after January 15, 1998 for the Company's 8.5%
+Convertible Subordinated Debentures due 2010 (the "Debentures") at a rate of
+$25.00 principal amount of Debentures for each share of Preferred Stock. The
+Debentures will be convertible into Common Stock of the Company on the same
+terms as the Preferred Stock and will pay interest semi-annually.
+In a December 1998 private transaction, a preferred stockholder elected to
+convert 59,689 shares of Preferred Stock into 136,867 shares of the Company's
+Common Stock. In 1999 certain other preferred stockholders, through private
+transactions, agreed to convert 210,350 shares of Preferred Stock into 502,637
+shares of the Company's Common Stock under similar terms. Likewise in 2000,
+444,600 shares of Preferred Stock were
+69
+converted into 1,036,098 shares of the Company's Common Stock. Any non-cash
+premium negotiated in excess of the conversion rate was recorded as additional
+preferred stock dividends and excluded from the Consolidated Statements of Cash
+Flows.
+The Company adopted a stockholder rights plan on March 30, 2000, designed to
+assure that the Company's stockholders receive fair and equal treatment in the
+event of any proposed takeover of the Company and to guard against partial
+tender offers, squeeze-outs, open market accumulations, and other abusive
+tactics to gain control without paying all stockholders a fair price. The rights
+plan was not adopted in response to any specific takeover proposal. Under the
+rights plan, the Company declared a dividend of one right ("Right") on each
+share of the Company's Common Stock. Each Right will entitle the holder to
+purchase one one-thousandth of a share of a Series B Preferred Stock, par value
+$0.01 per share, at an exercise price of $90 per one one-thousandth of a share.
+The Rights are not currently exercisable and will become exercisable only in the
+event a person or group acquires, or engages in a tender or exchange offer to
+acquire, beneficial ownership of 15 percent or more (one existing stockholder
+was granted an exception for up to 21 percent) of the Company's Common Stock.
+After the Rights become exercisable, each Right will also entitle its holder to
+purchase a number of common shares of the Company having a market value of twice
+the exercise price. The dividend distribution was made to stockholders of record
+at the close of business on April 10, 2000. The Rights will expire on March 30,
+2010.
+13. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)
+The Company's proved oil and gas reserves at December 31, 2003, 2002 and 2001
+have been estimated by independent petroleum consultants in accordance with
+guidelines established by the Securities and Exchange Commission ("SEC").
+Accordingly, the following reserve estimates are based upon existing economic
+and operating conditions. These estimates have been adjusted (per SEC
+guidelines) to exclude the volumetric production payment described in Note 2.
+There are numerous uncertainties inherent in establishing quantities of proved
+reserves. The following reserve data represents estimates only and should not be
+construed as being exact. In addition, the standard measure of discounted future
+net cash flows should not be construed as the current market value of the
+Company's oil and gas properties or the cost that would be incurred to obtain
+equivalent reserves. Reference the discussion in Note 7 regarding the Deep Water
+Royalty Relief Act and the potential loss of reserves.
+Beginning in October 2002, the Company received a series of inquiries from the
+SEC regarding its Annual Report on Form 10-K for the year ended December 31,
+2001 requesting supplemental information concerning its operations in the Gulf
+of Mexico. The comment letters requested information about the procedures the
+Company used to classify its deepwater reserves as proved and requested that the
+Company's financials be restated to reflect the removal of the Boomslang
+reserves as proved for all prior periods during which such reserves were
+reported as proved. The Company has reviewed the SEC comments with its
+independent petroleum reserve engineers, Huddleston & Co., Inc. of Houston,
+Texas. Both Huddleston & Co. and Callon believe that such deepwater reserves are
+properly classified as proved. If the SEC requires the Company to retroactively
+classify Boomslang as an unproved property through December, 2002, the Company
+would be required to restate its financial position, results of operations, and
+supplemental oil and gas reserve data from 1999 through 2003. The Company has
+responded to all of the SEC inquiries.
+70
+ESTIMATED RESERVES
+Changes in the estimated net quantities of crude oil and natural gas reserves,
+all of which are located onshore and offshore in the continental United States,
+are as follows:
+RESERVE QUANTITIES
+YEARS ENDED DECEMBER 31,
+------------------------
+2003 2002 2001
+---- ---- ----
+Proved developed and undeveloped reserves:
+Crude Oil (MBbls):
+Beginning of period 24,043 30,209 33,382
+Revisions to previous estimates (1) (8,699) (a) (2,290)
+Purchase of reserves in place -- -- --
+Sales of reserves in place (65) -- (624)
+Extensions and discoveries -- 2,759 (a) 14
+Production (268) (226) (273)
+------- ------- -------
+End of period 23,709 24,043 30,209
+======= ======= =======
+Natural Gas (MMcf):
+Beginning of period 91,539 120,299 129,922
+Revisions to previous estimates (6,407) (19,284) (a) (4,578)
+Purchase of reserves in place -- -- --
+Sales of reserves in place (49) -- (1,296)
+Extensions and discoveries 1,923 3,584 (a) 7,483
+Production (12,315) (13,060) (11,232)
+------- ------- -------
+End of period 74,691 91,539 120,299
+======= ======= =======
+Proved developed reserves:
+Crude Oil (MBbls):
+Beginning of period 1,056 885 2,192
+======= ======= =======
+End of period 9,919 1,056 885
+======= ======= =======
+Natural Gas (MMcf):
+Beginning of period 37,631 51,221 63,982
+======= ======= =======
+End of period 31,415 37,631 51,221
+======= ======= =======
+(a) For the year ended December 31, 2002, revisions to previous estimates and
+extensions and discoveries were adjusted from the amounts reported in the
+Company's Annual Report on Form 10-K dated March 27, 2003 to reflect the
+subsequent changes in properties that were part of property acquisitions or
+exploratory drilling programs and should have been classified as extensions
+instead of revisions.
+71
+STANDARDIZED MEASURE
+The following tables present the Company's standardized measure of discounted
+future net cash flows and changes therein relating to proved oil and gas
+reserves and were computed using reserve valuations based on regulations
+prescribed by the SEC. These regulations provide that the oil, condensate and
+gas price structure utilized to project future net cash flows reflects current
+prices (approximately $5.99 per Mcf for natural gas and $30.50 per Bbl for oil
+for the 2003 disclosures, $4.80 per Mcf and $34.22 per Bbl for 2002 disclosures,
+and $2.58 per Mcf and $20.10 per Bbl for 2001 disclosures) at each date
+presented and have not been escalated. Future production, development and net
+abandonment costs are based on current costs without escalation. The resulting
+net future cash flows have been discounted to their present values based on a
+10% annual discount factor.
+STANDARDIZED MEASURE
+YEARS ENDED DECEMBER 31,
+--------------------------------------
+2003 2002 2001
+----------- ----------- ----------
+(IN THOUSANDS)
+Future cash inflows $ 1,170,118 $ 1,261,571 $ 883,145
+Future costs -
+Production (219,421) (165,559) (220,857)
+Development and net abandonment (111,850) (125,813) (191,369)
+----------- ----------- ----------
+Future net inflows before income taxes 838,847 970,199 470,919
+Future income taxes (89,567) (119,020) (30,315)
+----------- ----------- ----------
+Future net cash flows 749,280 851,179 440,604
+10% discount factor (230,254) (295,133) (185,747)
+----------- ----------- ----------
+Standardized measure of discounted
+future net cash flows $ 519,026 $ 556,046 $ 254,857
+=========== =========== ==========
+CHANGES IN STANDARDIZED MEASURE
+YEARS ENDED DECEMBER 31,
+----------------------------------
+2003 2002 2001
+---------- --------- ---------
+(IN THOUSANDS)
+Standardized measure - beginning of period $ 556,046 $ 254,857 $ 671,197
+Sales and transfers, net of production costs (62,396) (38,375) (45,672)
+Net change in sales and transfer prices,
+net of production costs (41,011) 401,837 (604,391)
+Exchange and sale of in place reserves (1,226) -- (5,850)
+Purchases, extensions, discoveries, and improved
+recovery, net of future production and
+development costs incurred 25,632 8,456 9,358
+Revisions of quantity estimates (18,018) (103,452) (23,314)
+Accretion of discount 62,394 26,915 90,978
+Net change in income taxes 16,460 (53,608) 224,290
+Changes in production rates, timing and other (18,855) 59,416 (61,739)
+--------- --------- ---------
+Standardized measure - end of period $ 519,026 $ 556,046 $ 254,857
+========= ========= =========
+72
+14. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
+FIRST SECOND THIRD FOURTH
+QUARTER QUARTER QUARTER QUARTER
+-----------------------------------------
+(IN THOUSANDS, EXCEPT PER SHARE DATA)
+2003
+Total revenues $ 21,351 $ 18,482 $ 15,152 $ 19,156
+Total costs and expenses 19,503 19,477 18,270 26,623
+Income tax expense (benefit) 647 (348) (1,092) 9,225
+Income (loss) before cumulative effect of change
+in accounting principle 1,201 (647) (2,026) (16,700)
+Net income (loss) 1,382 (647) (2,026) (16,700)
+Net income (loss) per common share-basic:
+Net income (loss) available to common before
+cumulative effect of change in accounting principle $ 0.07 ($0.07) ($0.17) ($1.24)
+Cumulative effect of change in accounting principle,
+net of tax 0.01 0.00 0.00 0.00
+-------- ------- ------- -------
+Net income (loss) per share $ 0.08 ($0.07) ($0.17) ($1.24)
+Net income (loss) per common share-diluted:
+Net income (loss) available to common before
+cumulative effect of change in accounting principle $ 0.07 ($0.07) ($0.17) ($1.24)
+Cumulative effect of change in accounting principle,
+net of tax 0.01 0.00 0.00 0.00
+-------- ------- ------- -------
+Net income (loss) per share $ 0.08 ($0.07) (0.17) (1.24)
+2002
+Total revenues $ 11,624 $ 20,489 $ 15,786 $ 19,209
+Total costs and expenses 15,399 16,888 17,786 19,606
+Income tax expense (benefit) (1,321) 1,260 (700) (139)
+Net income (loss) (2,454) 2,341 (1,300) (258)
+Net income (loss) per share-basic (0.21) 0.15 (0.12) (0.04)
+Net income (loss) per share-diluted (0.21) 0.15 (0.12) (0.04)
+73
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
+FINANCIAL DISCLOSURE
+There have been no disagreements with the independent auditors on any matters of
+accounting principles or practices, financial statement disclosure, or auditing
+scope or procedures.
+ITEM 9A. CONTROLS AND PROCEDURES
+The term "disclosure controls and procedures" is defined in Rules 13a-15(e) and
+15d-15(e) of the Securities Exchange Act of 1934, or the Exchange Act. This term
+refers to the controls and procedures of a company that are designed to ensure
+that information required to be disclosed by a company in the reports that it
+files or submits under the Exchange Act is recorded, processed, summarized and
+reported within the time periods specified by the Securities and Exchange
+Commission. Our management, including our Chief Executive Officer and Chief
+Financial Officer, has evaluated the effectiveness of our disclosure controls
+and procedures as of the end of the period covered by this annual report. Based
+upon that evaluation, our Chief Executive Officer and Chief Financial Officer
+have concluded that our disclosure controls and procedures were effective as of
+the end of the period covered by this annual report.
+There were no changes to our internal control over financial reporting during
+our last fiscal quarter that has materially affected, or is reasonably likely to
+materially affect, our internal control over financial reporting.
+74
+PART III.
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
+For information concerning Item 10, see the definitive proxy statement of Callon
+Petroleum Company relating to the Annual Meeting of Stockholders on May 6, 2004
+which will be filed with the Securities and Exchange Commission and is
+incorporated herein by reference.
+ITEM 11. EXECUTIVE COMPENSATION.
+For information concerning Item 11, see the definitive proxy statement of Callon
+Petroleum Company relating to the Annual Meeting of Stockholders on May 6, 2004
+which will be filed with the Securities and Exchange Commission and is
+incorporated herein by reference.
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
+RELATED STOCKHOLDER MATTERS.
+For information concerning the security ownership of certain beneficial owners
+and management, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 6, 2004 which will be
+filed with the Securities and Exchange Commission and is incorporated herein by
+reference.
+EQUITY COMPENSATION PLAN INFORMATION
+The following table provides information as of December 31, 2003 regarding the
+number of shares of Common Stock that may be issued under the Company's equity
+compensation plans.
+Plan Category Number of securities to be Weighted-average Number of securities
+issued upon exercise of exercise price of remaining available for
+outstanding options, outstanding options, future issuance under
+warrants and rights warrants and rights equity compensation
+plans (excluding
+securities reflected
+in column (a)
+(A) (B) (C)
+--- --- ---
+Equity compensation
+plans approved by
+security holders(1) 2,264,667 $10.30 197,140
+Equity compensation
+plans not approved by
+security holders (2) 186,200 $ 4.33 75,317
+--------- ------ -------
+Total 2,450,867 $ 9.84 272,457
+========= ====== =======
+(1) Represents the Callon Petroleum Company 1994 and the 1996 Stock
+Incentive Plans which were approved by the shareholders in prior
+years. Remaining shares available for future
+75
+issuance listed in column (c) does not include 56,000 shares of
+restricted stock awarded in 2002 which have not yet vested.
+(2) Represents the Callon Petroleum Company 2002 Stock Incentive Plan
+adopted by the Company on February 14, 2002. The plan qualified as a
+"broadly based" plan under the provisions of the New York Stock
+Exchange rules and regulations and therefore did not require
+shareholder approval. Remaining shares available for future issuance
+listed in column (c) does not include 34,484 shares of restricted
+stock awarded in 2002 which have not yet vested.
+See Note 10 to the Consolidated Financial Statements for a description of the
+material provisions of each equity compensation plan under which our equity
+securities are authorized for issuance that was adopted without the approval of
+shareholders.
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
+For information concerning Item 13, see the definitive proxy statement of Callon
+Petroleum Company relating to the Annual Meeting of Stockholders on May 6, 2004
+which will be filed with the Securities and Exchange Commission and is
+incorporated herein by reference.
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
+For information concerning Item 14, see the definitive proxy statement of Callon
+Petroleum Company relating to the Annual Meeting of Stockholders on May 6, 2004
+which will be filed with the Securities and Exchange Commission and is
+incorporated herein by reference.
+76
+PART IV.
+ITEM15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
+(a) 1. The following is an index to the financial statements and financial
+statement schedules that are filed as part of this Form 10-K on pages 37 through
+63.
+Report of Independent Auditors
+Consolidated Balance Sheets as of the Years Ended December 31, 2003 and
+2002
+Consolidated Statements of Operations for the Three Years in the Period
+Ended December 31, 2003
+Consolidated Statements of Stockholders' Equity for the Three Years in the
+Period Ended December 31, 2003
+Consolidated Statements of Cash Flows for the Three Years in the Period
+Ended December 31, 2003
+Notes to Consolidated Financial Statements
+(a) 2. Schedules other than those listed above are omitted because they are not
+required, not applicable or the required information is included in the
+financial statements or notes thereto.
+(a) 3. Exhibits:
+2. Plan of acquisition, reorganization, arrangement, liquidation or
+succession*
+3. Articles of Incorporation and Bylaws
+3.1 Certificate of Incorporation of the Company, as amended
+3.2 Bylaws of the Company (incorporated by reference from Exhibit
+3.2 of the Company's Registration Statement on Form S-4, filed
+August 4, 1994, Reg. No. 33-82408)
+3.3 Certificate of Amendment to Certificate of Incorporation of
+the Company
+77
+4. Instruments defining the rights of security holders, including
+indentures
+4.1 Specimen Common Stock Certificate (incorporated by reference
+from Exhibit 4.1 of the Company's Registration Statement on
+Form S-4, filed August 4, 1994, Reg. No. 33-82408)
+4.2 Specimen Preferred Stock Certificate (incorporated by
+reference from Exhibit 4.2 of the Company's Registration
+Statement on Form S-1, filed November 13, 1995, Reg. No.
+33-96700)
+4.3 Designation for Convertible, Exchangeable Preferred Stock,
+Series A as corrected (included as part of Exhibit 3.1)
+4.4 Indenture for Convertible Debentures (incorporated by
+reference from Exhibit 4.4 of the Company's Registration
+Statement on Form S-1, filed November 13, 1995, Reg. No.
+33-96700)
+4.5 Indenture for the Company's 10.125% Senior Subordinated Notes
+due 2002 dated as of July 31, 1997 (incorporated by reference
+from Exhibit 4.1 of the Company's Registration Statement on
+Form S-4, filed September 25, 1997, Reg. No. 333-36395)
+4.6 Form of Note Indenture for the Company's 10.25% Senior
+Subordinated Notes due 2004 (incorporated by reference from
+Exhibit 4.10 of the Company's Registration Statement on Form
+S-2, filed June 14, 1999, Reg. No. 333-80579)
+4.7 Rights Agreement between Callon Petroleum Company and American
+Stock Transfer & Trust Company, Rights Agent, dated March 30,
+2000 (incorporated by reference from Exhibit 99.1 of the
+Company's Registration Statement on Form 8-A, filed April 6,
+2000, File No. 001-14039)
+4.8 Subordinated Indenture for the Company dated October 26, 2000
+(incorporated by reference from Exhibit 4.1 of the Company's
+Current Report on Form 8-K dated October 24, 2000, File No.
+001-14039)
+4.9 Supplemental Indenture for the Company's 11% Senior
+Subordinated Notes due 2005 (incorporated by reference from
+Exhibit 4.2 of the Company's Current Report on Form 8-K dated
+October 24, 2000, File No. 001-14039)
+4.10 Warrant dated as of June 29, 2001 entitling Duke Capital
+Partners, LLC to purchase common stock from the Company.
+(incorporated by reference to Exhibit 4.11 of the Company's
+Quarterly Report on Form 10-Q for the period ended June 30,
+2001, File No. 001-14039)
+78
+4.11 First Supplemental Indenture, dated June 26, 2002, to
+Indenture between Callon Petroleum Company and American Stock
+Transfer & Trust Company dated July 31, 1997. (incorporated by
+reference to Exhibit 4.1 of the Company's Current Report on
+Form 8-K dated June 26, 2002, File No. 001-14039)
+4.12 Form of Warrant entitling certain holders of the Company's
+10.125% Senior Subordinated Notes due 2002 to purchase common
+stock from the Company (incorporated by reference to Exhibit
+4.13 of the Company's Form 10-Q for the period ended June 30,
+2002, File No. 001- 14039)
+4.13 Second Supplemental Indenture, dated September 16, 2002, to
+Indenture between Callon Petroleum Company and American Stock
+Transfer & Trust Company dated July 31, 1997. (incorporated by
+reference to Exhibit 4.1 of the Company's Current Report on
+Form 8-K dated September 16, 2002, File No. 001-14039)
+4.14 Form of Warrants dated December 8, 2003 and December 29, 2003
+entitling lenders under the Company's $185 million amended and
+restated senior unsecured credit agreement dated December 23,
+2003 to purchase common stock from the Company
+9. Voting trust agreement
+None.
+10. Material contracts
+10.1 Registration Rights Agreement dated September 16, 1994 between
+the Company and NOCO Enterprises, L. P. (incorporated by
+reference from Exhibit 10.2 of the Company's Registration
+Statement on Form 8-B filed October 3, 1994)
+10.2 Counterpart to Registration Rights Agreement by and between
+the Company, Ganger Rolf ASA and Bonheur ASA. (incorporated by
+reference from Exhibit 10.2 of the Company's Report on Form
+10-K for the fiscal year ended December 31, 2000, File No.
+001-14039)
+10.3 Registration Rights Agreement dated September 16, 1994 between
+the Company and Callon Stockholders (incorporated by reference
+from Exhibit 10.3 of the Company's Registration Statement on
+Form 8-B filed October 3, 1994)
+10.4 Callon Petroleum Company 1994 Stock Incentive Plan
+(incorporated by reference from Exhibit 10.5 of the Company's
+Registration Statement on Form 8-B filed October 3, 1994)
+10.5 Consulting Agreement between the Company and John S. Callon
+dated June 19, 1996 (incorporated by reference from Exhibit
+10.10 of the Company's Registration Statement on Form S-1,
+filed November 5, 1996, Reg. No. 333-15501)
+10.6 Callon Petroleum Company Amended 1996 Stock Incentive Plan
+(incorporated by reference from Exhibit 4.4 of the
+Post-Effective Amendment No. 1 to the Company's Registration
+Statement on Form S-8, filed February 5, 1999, Reg. No.
+333-29537)
+79
+10.7 Purchase and Sale Agreement between Callon Petroleum Operating
+Company and Murphy Exploration Company, dated May 26, 1999
+(incorporated by reference from Exhibit 10.11 on Form S-2,
+filed June 14, 1999, Reg. No. 333-80579)
+10.8 Callon Petroleum Company 1996 Stock Incentive Plan as amended
+on May 9, 2000 (incorporated by reference from Appendix I of
+the Company's Definitive Proxy Statement of Schedule 14A filed
+March 28, 2000)
+10.9 Credit Agreement dated as of October 30, 2000 between the
+Company and First Union National Bank, as administrative agent
+for the lenders (incorporated by reference from Exhibit 10.2
+of the Company's Quarterly Report on Form 10-Q for the period
+ended September 30, 2000, File No. 001-14039)
+10.10 Credit Agreement dated as of June 29, 2001 between the Company
+and Duke Capital Partners, LLC, as Administrative Agent
+(incorporated by reference to Exhibit 10.01 of the Company's
+Quarterly Report on Form 10-Q for the period ended June 30,
+2001, File No. 001-14039)
+10.11 Second Amendment to Credit Agreement by and among the Company
+and First Union National Bank, as Administrative Agent,
+effective as of June 29, 2001 (incorporated by reference to
+Exhibit 10.01 of the Company's Quarterly Report on Form 10-Q
+for the period ended June 30, 2001, File No. 001-14039)
+10.12 Conveyance of Overriding Royalty Interest from the Company to
+Duke Capital Partners, LLC, dated June 29, 2001 (incorporated
+by reference to Exhibit 10.03 of the Company's Quarterly
+Report on Form 10-Q for the period ended June 30, 2001, File
+No. 001-14039)
+10.13 Callon Petroleum Company 2002 Stock Incentive Plan
+(incorporated by reference to Exhibit 10.13 of the Company's
+Annual Report on Form 10-K for the year ended December 31,
+2001, File No. 001-14039)
+10.14 Change of Control Severance Compensation Agreement by and
+between Callon Petroleum and John S. Weatherly dated January
+1, 2002 (incorporated by reference to Exhibit 10.14 of the
+Company's Annual Report on Form 10-K for the year ended
+December 31, 2001, File No. 001-14039)
+10.15 Change of Control Severance Compensation Agreement by and
+between Callon Petroleum Company and Fred L. Callon, dated
+January 1, 2002 (incorporated by reference to Exhibit 10.15 of
+the Company's Annual Report on Form 10-K for the year ended
+December 31, 2001, File No. 001-14039)
+10.16 Change of Control Severance Compensation Agreement by and
+between Callon Petroleum Company and Dennis W. Christian,
+dated January 1, 2002 (incorporated by reference to Exhibit
+10.16 of the Company's Annual Report on Form 10-K for the year
+ended December 31, 2001, File No. 001-14039)
+80
+10.17 First Amended and Restated Credit Agreement dated as of June
+30, 2002, among Callon Petroleum Company, each of the lenders
+that is a signatory thereto, Wachovia Bank National
+Association, as administrative agent, and Union Bank of
+California, N.A., as documentation agent (incorporated by
+reference to Exhibit 10.1 of the Company's Form 10-Q for the
+period ended June 30, 2002, File No. 001-14039)
+10.18 Amended and Restated Credit Agreement Dated as of December 23,
+2003, among Callon Petroleum Company, each of the lenders that
+is signatory thereto or which becomes a signatory thereto; and
+Wells Fargo Bank, National Association, a National Banking
+Association, as administrative agent
+10.19 Medusa Spar Agreement dated as of August 8, 2003, among Callon
+Petroleum Operating Company, Murphy Exploration & Production
+Company-USA and Oceaneering International, Inc.
+10.20 Credit Agreement dated as of December 18, 2003 among Medusa
+Spar LLC, The Bank of Nova Scotia, as Administrative Agent,
+Bank One, N.A., Sun Trust Bank, as Syndication Agents and
+other Lenders Party.
+10.21 The Retirement Package and Release Agreement made, entered
+into and effective March 9, 2004 between Callon Petroleum
+Company and Dennis W. Christian.
+10.22 The Retirement Package and Release Agreement made, entered
+into and effective March 9, 2004 between Callon Petroleum
+Company and Kathy G. Tilley.
+11. Statement re computation of per share earnings*
+12. Statements re computation of ratios*
+13. Annual Report to security holders, Form 10-Q or quarterly reports*
+14. Code of Ethics
+14.1 Code of Ethics for Chief Executives Officer and Senior
+Financial Officers
+16. Letter re change in certifying accountant*
+81
+18. Letter re change in accounting principles*
+21. Subsidiaries of the Company
+21.1 Subsidiaries of the Company (incorporated by reference from
+Exhibit 21.1 of the Company's Registration Statement on Form
+8-B filed October 3, 1994)
+22. Published report regarding matters submitted to vote of security
+holders*
+23. Consents of experts and counsel
+23.1 Consent of Ernst & Young LLP
+24. Power of attorney*
+31. Rule 13a-14(a) Certifications
+31.1 Certification of Chief Executive Officer pursuant to Rule
+13(a)-14(a)
+31.2 Certification of Chief Financial Officer pursuant to Rule
+13(a)-14(a)
+32. Section 1350 Certifications
+32.1 Certification of Chief Executive Officer pursuant to Rule
+13(a)-14(b)
+32.2 Certification of Chief Financial Officer pursuant to Rule
+13(a)-14(b)
+99. Additional Exhibits*
+----------
+*Inapplicable to this filing.
+(b) Reports on Form 8-K.
+Current Report on Form 8-K dated November 11, 2003, reporting Item 12.
+Results of Operations and Financial Condition
+Current Report on Form 8-K dated December 1, 2003, reporting Item 9.
+Regulation FD Disclosure
+Current Report on Form 8-K dated December 8, 2003, reporting Item 9.
+Regulation FD Disclosure
+Current Report on Form 8-K dated January 23, 2004 reporting Item 5. Other
+Events
+82
+SIGNATURES
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report
+has been signed below by the following persons on behalf of the registrant and
+in the capacities and on the dates indicated.
+CALLON PETROLEUM COMPANY
+Date: March 15, 2004 /s/ Fred L. Callon
+--------------------------------------
+Fred L. Callon (principal executive
+officer, director)
+Date: March 15, 2004 /s/ John S. Weatherly
+--------------------------------------
+John S. Weatherly (principal
+financial officer)
+Date: March 15, 2004 /s/ Rodger W. Smith
+--------------------------------------
+Rodger W. Smith (principal
+accounting officer)
+Date: March 15, 2004 /s/ John S. Callon
+--------------------------------------
+John S. Callon (director)
+Date: March 15, 2004 /s/ Leif Dons
+--------------------------------------
+Leif Dons (director)
+Date: March 15, 2004 /s/ Robert A. Stanger
+--------------------------------------
+Robert A. Stanger (director)
+Date: March 15, 2004 /s/ John C. Wallace
+--------------------------------------
+John C. Wallace (director)
+Date: March 15, 2004 /s/ B. F. Weatherly
+--------------------------------------
+B. F. Weatherly (director)
+Date: March 15, 2004 /s/ Richard O. Wilson
+--------------------------------------
+Richard O. Wilson (director)
+83
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
+Act of 1934, the registrant has duly caused this report to be signed on its
+behalf by the undersigned, thereunto duly authorized.
+CALLON PETROLEUM COMPANY
+Date: March 15, 2004 By: /s/ John S. Weatherly
+--------------------------------------
+John S. Weatherly, Senior Vice
+President and Chief Financial Officer
+84
+INDEX TO EXHIBITS
+2. Plan of acquisition, reorganization, arrangement, liquidation or
+succession*
+3. Articles of Incorporation and Bylaws
+3.1 Certificate of Incorporation of the Company, as amended
+3.2 Bylaws of the Company (incorporated by reference from Exhibit
+3.2 of the Company's Registration Statement on Form S-4, filed
+August 4, 1994, Reg. No. 33-82408)
+3.3 Certificate of Amendment to Certificate of Incorporation of
+the Company
+4. Instruments defining the rights of security holders, including
+indentures
+4.1 Specimen Common Stock Certificate (incorporated by reference
+from Exhibit 4.1 of the Company's Registration Statement on
+Form S-4, filed August 4, 1994, Reg. No. 33-82408)
+4.2 Specimen Preferred Stock Certificate (incorporated by
+reference from Exhibit 4.2 of the Company's Registration
+Statement on Form S-1, filed November 13, 1995, Reg. No.
+33-96700)
+4.3 Designation for Convertible, Exchangeable Preferred Stock,
+Series A as corrected (included as part of Exhibit 3.1)
+4.4 Indenture for Convertible Debentures (incorporated by
+reference from Exhibit 4.4 of the Company's Registration
+Statement on Form S-1, filed November 13, 1995, Reg. No.
+33-96700)
+4.5 Indenture for the Company's 10.125% Senior Subordinated Notes
+due 2002 dated as of July 31, 1997 (incorporated by reference
+from Exhibit 4.1 of the Company's Registration Statement on
+Form S-4, filed September 25, 1997, Reg. No. 333-36395)
+4.6 Form of Note Indenture for the Company's 10.25% Senior
+Subordinated Notes due 2004 (incorporated by reference from
+Exhibit 4.10 of the Company's Registration Statement on Form
+S-2, filed June 14, 1999, Reg. No. 333-80579)
+4.7 Rights Agreement between Callon Petroleum Company and American
+Stock Transfer & Trust Company, Rights Agent, dated March 30,
+2000 (incorporated by reference from Exhibit 99.1 of the
+Company's Registration Statement on Form 8-A, filed April 6,
+2000, File No. 001-14039)
+4.8 Subordinated Indenture for the Company dated October 26, 2000
+(incorporated by reference from Exhibit 4.1 of the Company's
+Current Report on Form 8-K dated October 24, 2000, File No.
+001-14039)
+4.9 Supplemental Indenture for the Company's 11% Senior
+Subordinated Notes due 2005 (incorporated by reference from
+Exhibit 4.2 of the Company's Current Report on Form 8-K dated
+October 24, 2000, File No. 001-14039)
+4.10 Warrant dated as of June 29, 2001 entitling Duke Capital
+Partners, LLC to purchase common stock from the Company.
+(incorporated by reference to Exhibit 4.11 of the Company's
+Quarterly Report on Form 10-Q for the period ended June 30,
+2001, File No. 001-14039)
+4.11 First Supplemental Indenture, dated June 26, 2002, to
+Indenture between Callon Petroleum Company and American Stock
+Transfer & Trust Company dated July 31, 1997. (incorporated by
+reference to Exhibit 4.1 of the Company's Current Report on
+Form 8-K dated June 26, 2002, File No. 001-14039)
+4.12 Form of Warrant entitling certain holders of the Company's
+10.125% Senior Subordinated Notes due 2002 to purchase common
+stock from the Company (incorporated by reference to Exhibit
+4.13 of the Company's Form 10-Q for the period ended June 30,
+2002, File No. 001- 14039)
+4.13 Second Supplemental Indenture, dated September 16, 2002, to
+Indenture between Callon Petroleum Company and American Stock
+Transfer & Trust Company dated July 31, 1997. (incorporated by
+reference to Exhibit 4.1 of the Company's Current Report on
+Form 8-K dated September 16, 2002, File No. 001-14039)
+4.14 Form of Warrants dated December 8, 2003 and December 29, 2003
+entitling lenders under the Company's $185 million amended and
+restated senior unsecured credit agreement dated December 23,
+2003 to purchase common stock from the Company
+9. Voting trust agreement
+None.
+10. Material contracts
+10.1 Registration Rights Agreement dated September 16, 1994 between
+the Company and NOCO Enterprises, L. P. (incorporated by
+reference from Exhibit 10.2 of the Company's Registration
+Statement on Form 8-B filed October 3, 1994)
+10.2 Counterpart to Registration Rights Agreement by and between
+the Company, Ganger Rolf ASA and Bonheur ASA. (incorporated by
+reference from Exhibit 10.2 of the Company's Report on Form
+10-K for the fiscal year ended December 31, 2000, File No.
+001-14039)
+10.3 Registration Rights Agreement dated September 16, 1994 between
+the Company and Callon Stockholders (incorporated by reference
+from Exhibit 10.3 of the Company's Registration Statement on
+Form 8-B filed October 3, 1994)
+10.4 Callon Petroleum Company 1994 Stock Incentive Plan
+(incorporated by reference from Exhibit 10.5 of the Company's
+Registration Statement on Form 8-B filed October 3, 1994)
+10.5 Consulting Agreement between the Company and John S. Callon
+dated June 19, 1996 (incorporated by reference from Exhibit
+10.10 of the Company's Registration Statement on Form S-1,
+filed November 5, 1996, Reg. No. 333-15501)
+10.6 Callon Petroleum Company Amended 1996 Stock Incentive Plan
+(incorporated by reference from Exhibit 4.4 of the
+Post-Effective Amendment No. 1 to the Company's Registration
+Statement on Form S-8, filed February 5, 1999, Reg. No.
+333-29537)
+10.7 Purchase and Sale Agreement between Callon Petroleum Operating
+Company and Murphy Exploration Company, dated May 26, 1999
+(incorporated by reference from Exhibit 10.11 on Form S-2,
+filed June 14, 1999, Reg. No. 333-80579)
+10.8 Callon Petroleum Company 1996 Stock Incentive Plan as amended
+on May 9, 2000 (incorporated by reference from Appendix I of
+the Company's Definitive Proxy Statement of Schedule 14A filed
+March 28, 2000)
+10.9 Credit Agreement dated as of October 30, 2000 between the
+Company and First Union National Bank, as administrative agent
+for the lenders (incorporated by reference from Exhibit 10.2
+of the Company's Quarterly Report on Form 10-Q for the period
+ended September 30, 2000, File No. 001-14039)
+10.10 Credit Agreement dated as of June 29, 2001 between the Company
+and Duke Capital Partners, LLC, as Administrative Agent
+(incorporated by reference to Exhibit 10.01 of the Company's
+Quarterly Report on Form 10-Q for the period ended June 30,
+2001, File No. 001-14039)
+10.11 Second Amendment to Credit Agreement by and among the Company
+and First Union National Bank, as Administrative Agent,
+effective as of June 29, 2001 (incorporated by reference to
+Exhibit 10.01 of the Company's Quarterly Report on Form 10-Q
+for the period ended June 30, 2001, File No. 001-14039)
+10.12 Conveyance of Overriding Royalty Interest from the Company to
+Duke Capital Partners, LLC, dated June 29, 2001 (incorporated
+by reference to Exhibit 10.03 of the Company's Quarterly
+Report on Form 10-Q for the period ended June 30, 2001, File
+No. 001-14039)
+10.13 Callon Petroleum Company 2002 Stock Incentive Plan
+(incorporated by reference to Exhibit 10.13 of the Company's
+Annual Report on Form 10-K for the year ended December 31,
+2001, File No. 001-14039)
+10.14 Change of Control Severance Compensation Agreement by and
+between Callon Petroleum and John S. Weatherly dated January
+1, 2002 (incorporated by reference to Exhibit 10.14 of the
+Company's Annual Report on Form 10-K for the year ended
+December 31, 2001, File No. 001-14039)
+10.15 Change of Control Severance Compensation Agreement by and
+between Callon Petroleum Company and Fred L. Callon, dated
+January 1, 2002 (incorporated by reference to Exhibit 10.15 of
+the Company's Annual Report on Form 10-K for the year ended
+December 31, 2001, File No. 001-14039)
+10.16 Change of Control Severance Compensation Agreement by and
+between Callon Petroleum Company and Dennis W. Christian,
+dated January 1, 2002 (incorporated by reference to Exhibit
+10.16 of the Company's Annual Report on Form 10-K for the year
+ended December 31, 2001, File No. 001-14039)
+10.17 First Amended and Restated Credit Agreement dated as of June
+30, 2002, among Callon Petroleum Company, each of the lenders
+that is a signatory thereto, Wachovia Bank National
+Association, as administrative agent, and Union Bank of
+California, N.A., as documentation agent (incorporated by
+reference to Exhibit 10.1 of the Company's Form 10-Q for the
+period ended June 30, 2002, File No. 001-14039)
+10.18 Amended and Restated Credit Agreement Dated as of December 23,
+2003, among Callon Petroleum Company, each of the lenders that
+is signatory thereto or which becomes a signatory thereto; and
+Wells Fargo Bank, National Association, a National Banking
+Association, as administrative agent
+10.19 Medusa Spar Agreement dated as of August 8, 2003, among Callon
+Petroleum Operating Company, Murphy Exploration & Production
+Company-USA and Oceaneering International, Inc.
+10.20 Credit Agreement dated as of December 18, 2003 among Medusa
+Spar LLC, The Bank of Nova Scotia, as Administrative Agent,
+Bank One, N.A., Sun Trust Bank, as Syndication Agents and
+other Lenders Party.
+10.21 The Retirement Package and Release Agreement made, entered
+into and effective March 9, 2004 between Callon Petroleum
+Company and Dennis W. Christian.
+10.22 The Retirement Package and Release Agreement made, entered
+into and effective March 9, 2004 between Callon Petroleum
+Company and Kathy G. Tilley.
+11. Statement re computation of per share earnings*
+12. Statements re computation of ratios*
+13. Annual Report to security holders, Form 10-Q or quarterly reports*
+14. Code of Ethics
+14.1 Code of Ethics for Chief Executives Officer and Senior
+Financial Officers
+16. Letter re change in certifying accountant*
+18. Letter re change in accounting principles*
+21. Subsidiaries of the Company
+21.1 Subsidiaries of the Company (incorporated by reference from
+Exhibit 21.1 of the Company's Registration Statement on Form
+8-B filed October 3, 1994)
+22. Published report regarding matters submitted to vote of security
+holders*
+23. Consents of experts and counsel
+23.1 Consent of Ernst & Young LLP
+24. Power of attorney*
+31. Rule 13a-14(a) Certifications
+31.1 Certification of Chief Executive Officer pursuant to Rule
+13(a)-14(a)
+31.2 Certification of Chief Financial Officer pursuant to Rule
+13(a)-14(a)
+32. Section 1350 Certifications
+32.1 Certification of Chief Executive Officer pursuant to Rule
+13(a)-14(b)
+32.2 Certification of Chief Financial Officer pursuant to Rule
+13(a)-14(b)
+99. Additional Exhibits*
+----------
+*Inapplicable to this filing.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2003/0000950134-04-003498/filing_metadata.csv b/raw/filings/0000928022/2003/0000950134-04-003498/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..a4337fc7d40015dd4d706ccd53f692dee004b3f6
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+0000928022,CPE,Callon Petroleum Co,10-K,2004-03-15,2003-12-31,2004-03-15T20:08:05.000Z,0000950134-04-003498,d13486e10vk.txt,FORM 10-K,1223542,0,0,https://www.sec.gov/Archives/edgar/data/928022/000095013404003498/d13486e10vk.txt,https://www.sec.gov/Archives/edgar/data/928022/000095013404003498/,2003,2003,1
diff --git a/raw/filings/0000928022/2003/0000950134-04-003498/item1.txt b/raw/filings/0000928022/2003/0000950134-04-003498/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..ccb4eda3464ffa12b2f25bd01f0d77b6d31ba832
--- /dev/null
+++ b/raw/filings/0000928022/2003/0000950134-04-003498/item1.txt
@@ -0,0 +1,3662 @@
+ITEM 1 AND 2. BUSINESS AND PROPERTIES
+OVERVIEW
+Callon Petroleum Company has been engaged in the exploration, development,
+acquisition and production of oil and gas properties since 1950. Our properties
+are geographically concentrated primarily offshore in the Gulf of Mexico and
+onshore in Louisiana and Alabama. We were incorporated under the laws of the
+state of Delaware in 1994 and succeeded to the business of a publicly traded
+limited partnership, a joint venture with a consortium of European institutional
+investors and an independent energy company owned by members of current
+management. As used herein, the "Company," "Callon," "we," "us," and "our" refer
+to Callon Petroleum Company and its predecessors and subsidiaries unless the
+context requires otherwise.
+In 1989, we began increasing our reserves through the acquisition of producing
+properties that were geologically complex, had (or were analogous to fields
+with) an established production history from stacked pay zones and were
+candidates for exploitation. We focused on reducing operating costs and
+implementing production enhancements through the application of technologically
+advanced production and recompletion techniques.
+Over the past eight years, we have also placed emphasis on the acquisition of
+acreage with exploration and development drilling opportunities in the Gulf of
+Mexico shelf and deepwater areas. At December 31, 2003 we owned working
+interests in a total of 73 blocks/leases covering 157,000 net acres. We joined
+with other industry partners, primarily Murphy Exploration and Production, Inc.,
+to explore federal offshore blocks acquired in the Gulf of Mexico. We perform
+extensive geological and geophysical studies using computer-aided exploration
+techniques (CAEX), including, where appropriate, the acquisition of 3-D seismic
+or high-resolution 2-D data to facilitate these efforts. We continue to develop
+prospects on the shelf through our 3-D seismic partnership using AVO technology.
+In 1998, we began exploration in the Gulf of Mexico deepwater area (generally
+900 to 5,500 feet of water). In the fourth quarter of 2003, our first two
+deepwater projects, the Medusa and Habanero fields, began production. Please see
+"Significant Properties" for a more detailed discussion.
+We ended the year 2003 with estimated net proved reserves of 217 billion cubic
+feet of natural gas equivalent ("Bcfe"). This represents a decrease of 8% from
+2002 year-end estimated net proved reserves of 236 Bcfe.
+The major focus of our future operations is expected to continue to be the
+exploration for and development of oil and gas properties, primarily in the Gulf
+of Mexico.
+AVAILABILITY OF REPORTS
+All of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current
+reports on Form 8-K, and amendments to such reports as well as other filings we
+make pursuant to Section 13(a) and 15(d) of the Securities Exchange Act of 1934
+are available free of charge on our Internet website. The address of our
+Internet website is www.callon.com. Our SEC filings are available on our website
+as soon as they are posted to the EDGAR database on the SEC's website.
+2
+BUSINESS STRATEGY
+Our goal is to increase shareholder value by increasing our reserves,
+production, cash flow and earnings. We seek to achieve these goals through the
+following strategies:
+- focus on Gulf of Mexico exploration with a balance between shelf and
+deepwater areas using the latest available technology;
+- aggressively explore our existing prospect inventory;
+- replenish our prospect inventory with increasing emphasis on
+prospect generation using AVO technology;
+- achieve moderate increases in current production levels through
+continued shelf exploration; and
+- achieve significant increases in longer-term production levels
+through development of deepwater discoveries and ongoing deepwater
+exploration.
+EXPLORATION AND DEVELOPMENT ACTIVITIES
+Capital expenditures for exploration and development costs related to oil and
+gas properties totaled approximately $50 million in 2003. We incurred
+approximately $32 million in the Gulf of Mexico deepwater area primarily for
+development costs at our Habanero and Medusa discoveries. Interest of
+approximately $5 million and general and administrative costs allocable directly
+to exploration and development projects of $8 million were capitalized in 2003.
+Our Gulf of Mexico shelf area expenditures account for the remainder of the
+total capital expended.
+SEC INQUIRIES REGARDING RESERVE INFORMATION
+Beginning in October 2002, we received a series of inquiries from the SEC
+regarding our Annual Report on Form 10-K for the year ended December 31, 2001
+requesting supplemental information concerning operations in the Gulf of Mexico.
+The comment letters requested information about the procedures used to classify
+the deepwater reserves as proved and requested that our financial statements be
+restated to reflect the removal of the reserves attributable to the Boomslang
+discovery as proved for all prior periods during which such reserves were
+reported as proved. We have reviewed the SEC comments with our independent
+petroleum reserve engineers, Huddleston & Co., Inc. of Houston, Texas. Both
+Huddleston & Co. and we believe that such deepwater reserves are properly
+classified as proved. We have responded to all the inquiries from the SEC.
+Based on our discussions with others in the oil and gas business, we believe
+that the SEC is reviewing generally the procedures used by reserve engineers to
+classify oil and gas reserves as proved in the deepwater areas of the Gulf of
+Mexico. In particular, the SEC appears to indicate that it is not appropriate to
+classify reserves as proved without conducting a "flow test." It has not been
+our practice to conduct a flow test on our deepwater properties prior to
+classifying the reserves as proved. We believe, and have been advised by
+Huddleston & Co., that our procedures for classifying our deepwater reserves as
+proved are in accordance with SEC rules and industry practices.
+RISK FACTORS
+A DECREASE IN OIL AND GAS PRICES MAY ADVERSELY AFFECT OUR RESULTS OF OPERATIONS
+AND FINANCIAL CONDITION. Our success is highly dependent on prices for oil and
+gas, which are extremely volatile. Any
+3
+substantial or extended decline in the price of oil or gas would have a material
+adverse effect on us. Oil and gas markets are both seasonal and cyclical. The
+prices of oil and gas depend on factors we cannot control such as weather,
+economic conditions, and levels of production, actions by OPEC and other
+countries and government actions. Prices of oil and gas will affect the
+following aspects of our business:
+- our revenues, cash flows and earnings;
+- the amount of oil and gas that we are economically able to produce;
+- our ability to attract capital to finance our operations and the
+cost of the capital;
+- the amount we are allowed to borrow under our senior secured credit
+facility;
+- the value of our oil and gas properties; and
+- the profit or loss we incur in exploring for and developing our
+reserves.
+WE MAY BE REQUIRED TO RETROACTIVELY PAY ROYALTIES TO THE MINERALS MANAGEMENT
+SERVICE ON ONE OF OUR PROPERTIES WHICH COULD REDUCE REVENUES AND RESERVES. Our
+Medusa deepwater property is eligible for royalty suspensions pursuant to the
+Deep Water Royalty Relief Act. However, the federal offshore leases covering the
+property contain "price threshold" provisions for oil and gas prices. Under this
+"price threshold" provision, if the average monthly New York Mercantile Exchange
+(NYMEX) sales price for oil or gas during a fiscal year exceeds the price
+threshold for oil or gas, respectively, then royalties on the associated
+production must be paid to the Minerals Management Service (MMS) at the rate
+stipulated in the lease. The price thresholds are adjusted annually by the
+implicit price deflator for the GDP. The determination of whether or not
+royalties are due as a result of the average NYMEX price exceeding the price
+threshold is made during the first quarter of the succeeding year. Any royalty
+payments due must be made shortly after this determination is made. If a royalty
+payment is due for all production during a year as a result of exceeding the
+price threshold, the lessee is required to make monthly royalty payments during
+the succeeding fiscal year for the succeeding year's production. If at the end
+of any year the average NYMEX price is below the price threshold, the lessee can
+apply for a refund for any associated royalties paid during that year and the
+lessee will not be required to pay royalties monthly during the succeeding year
+for the succeeding year's production.
+The thresholds and the average NYMEX prices are calculated by the MMS. The
+average NYMEX price for 2003 was $31.08 per barrel of oil and $5.49 per MMBtu of
+natural gas. For the year ended December 31, 2003 the thresholds were $32.77 per
+barrel of oil and $4.10 per MMBtu of natural gas, subject to finalization of the
+adjustment for the 2003 GDP implicit price deflator. As a result we will pay
+royalties related to 2003 gas production for Medusa, which commenced production
+in late November 2003 and will make monthly royalty payments for 2004 gas
+production during 2004. Our actual liability for 2004 oil royalties, if any,
+cannot be determined until after the end of 2004.
+In the year succeeding the year in which any of our properties became subject to
+royalties as result of the average NYMEX price exceeding the price threshold,
+the portion of reserves attributable to potential future royalties would not be
+included in a year-end reserve report. However, if the average NYMEX prices were
+below the price thresholds in subsequent years, our reserves would be increased
+to reflect reserves previously attributed to future royalties. As a result,
+reported oil and gas reserves could materially increase or decrease, depending
+on the relation of price thresholds versus the average NYMEX prices. The
+reduction in our revenues resulting from an obligation to pay these royalties
+and subsequent reduction of our proved reserves could have a material adverse
+effect on our results of operations and financial condition. Our reserve report,
+as of December 31, 2003, excluded gas reserves for Medusa that are subject to
+MMS royalties as a result of the average 2003 NYMEX price for gas exceeding the
+price threshold. Oil reserves in this reserve report were not impacted since the
+2003 average NYMEX price was below the threshold.
+4
+OUR RESERVE INFORMATION REPRESENTS ESTIMATES THAT MAY TURN OUT TO BE INCORRECT
+IF THE ASSUMPTIONS UPON WHICH THESE ESTIMATES ARE BASED ARE INACCURATE. ANY
+MATERIAL INACCURACIES IN THESE RESERVE ESTIMATES OR UNDERLYING ASSUMPTIONS WILL
+MATERIALLY AFFECT THE QUANTITIES AND PRESENT VALUE OF OUR RESERVES. The process
+of estimating oil and gas reserves is complex. It requires interpretations of
+available technical data and various assumptions, including assumptions relating
+to economic factors. Any significant inaccuracies in these interpretations or
+assumptions could materially affect the estimated quantities and present value
+of reserves shown in this annual report.
+In order to prepare these estimates, we must project production rates and the
+timing of development expenditures. The assumptions regarding the timing and
+costs to commence production from our deepwater wells used in preparing our
+reserves are often subject to revisions over time as described under "our
+deepwater operations have special operational risks that may negatively affect
+the value of those assets." We must also analyze available geological,
+geophysical, production and engineering data, the extent, quality and
+reliability of which can vary. The process also requires us to make economic
+assumptions, such as oil and gas prices, drilling and operating expenses,
+capital expenditures, taxes and availability of funds. Therefore, estimates of
+oil and gas reserves are inherently imprecise.
+Actual future production, oil and gas prices, revenues, taxes, development
+expenditures, operating expenses and quantities of recoverable oil and gas
+reserves most likely will vary from our estimates. Any significant variance
+could materially affect the estimated quantities and present value of reserves
+shown in this report. In addition, we may adjust estimates of proved reserves to
+reflect production history, results of exploration and development, prevailing
+oil and gas prices and other factors, many of which are beyond our control.
+You should not assume that the present value of future net cash flows from our
+proved reserves referred to in this report is the current market value of our
+estimated oil and gas reserves. In accordance with SEC requirements, we
+generally base the estimated discounted future net cash flows from our proved
+reserves on prices and costs on the date of the estimate. Actual future prices
+and costs may differ materially from those used in the present value estimate.
+Information about reserves constitutes forward-looking information. See
+"Forward-Looking Statements" for information regarding forward-looking
+information. The discounted present value of our oil and gas reserves is
+prepared in accordance with guidelines established by the SEC. A purchaser of
+reserves would use numerous other factors to value our reserves. The discounted
+present value of reserves, therefore, does not represent the fair market value
+of those reserves.
+On December 31, 2003, approximately 53% of the discounted present value of our
+estimated net proved reserves were proved undeveloped. Proved undeveloped oil
+volumes represented 58% of total proved oil reserves. Substantially all of these
+proved undeveloped reserves were attributable to our deepwater properties.
+Development of these properties is subject to additional risks as described
+above.
+THE SEC MAY REQUIRE US TO BOOK RESERVES AS PROVED IN A MANNER THAT DIFFERS FROM
+OUR HISTORICAL PRACTICES AND CURRENT INDUSTRY STANDARDS, AND WHICH MAY RESULT IN
+A SIGNIFICANT DOWNWARD REVISION OF OUR PROVED RESERVES. As discussed above,
+beginning in October 2002 we received a series of inquiries from the SEC
+regarding our Annual Report on Form 10-K for the year ended December 31, 2001
+requesting supplemental information concerning our operations in the Gulf of
+Mexico. The comment
+5
+letters requested information about the procedures we used to classify our
+deepwater reserves as proved and requested that our financials be restated to
+reflect the removal of the Boomslang reserves as proved for all prior periods
+during which such reserves were reported as proved. We have reviewed the SEC
+comments with our independent petroleum reserve engineers, Huddleston & Co.,
+Inc. of Houston, Texas. Both Huddleston & Co. and we believe that such reserves
+were properly classified as proved. However, if the SEC decides to question our
+other deepwater properties and these reserves are ultimately required to be
+reclassified as not proved, our proved reserves will be materially reduced. If
+the SEC requires us to retroactively classify Boomslang as an unproved property
+through December 2002, we would be required to restate our financial position,
+results of operations, and supplemental oil and gas reserve data from 1998
+through 2002. A material reduction in our proved reserves could have a material
+adverse effect on our financial condition and results of operations. We have
+responded to all the inquiries from the SEC.
+UNLESS WE ARE ABLE TO REPLACE RESERVES WHICH WE HAVE PRODUCED, OUR CASH FLOWS
+AND PRODUCTION WILL DECREASE OVER TIME. Our future success depends upon our
+ability to find, develop and acquire oil and gas reserves that are economically
+recoverable. As is generally the case for Gulf properties, our producing
+properties usually have high initial production rates, followed by a steep
+decline in production. As a result, we must continually locate and develop or
+acquire new oil and gas reserves to replace those being depleted by production.
+We must do this even during periods of low oil and gas prices when it is
+difficult to raise the capital necessary to finance these activities and during
+periods of high operating costs when it is expensive to contract for drilling
+rigs and other equipment and personnel necessary to explore for oil and gas.
+Without successful exploration or acquisition activities, our reserves,
+production and revenues will decline rapidly. We cannot assure you that we will
+be able to find and develop or acquire additional reserves at an acceptable
+cost.
+A SIGNIFICANT PART OF THE VALUE OF OUR PRODUCTION AND RESERVES IS CONCENTRATED
+IN A SMALL NUMBER OF OFFSHORE PROPERTIES, AND ANY PRODUCTION PROBLEMS OR
+INACCURACIES IN RESERVE ESTIMATES RELATED TO THOSE PROPERTIES WOULD ADVERSELY
+IMPACT OUR BUSINESS. During 2003, 64% of our daily production came from two of
+our properties in the Gulf of Mexico. Moreover, one property accounted for 51%
+of our production during this period. In addition, at December 31, 2003, most of
+our proved reserves were located in four fields in the Gulf of Mexico, with
+approximately 94% of our total net proved reserves attributable to these
+properties. If mechanical problems, storms or other events curtailed a
+substantial portion of this production or if the actual reserves associated with
+any one of these producing properties are less than our estimated reserves, our
+results of operations and financial condition could be adversely affected.
+OUR FOCUS ON EXPLORATION PROJECTS INCREASES THE RISKS INHERENT IN OUR OIL AND
+GAS ACTIVITIES. Our business strategy focuses on replacing reserves through
+exploration, where the risks are greater than in acquisitions and development
+drilling. Although we have been successful in exploration in the past, we cannot
+assure you that we will continue to increase reserves through exploration or at
+an acceptable cost. Additionally, we are often uncertain as to the future costs
+and timing of drilling, completing and producing wells. Our drilling operations
+may be curtailed, delayed or canceled as a result of a variety of factors,
+including:
+- unexpected drilling conditions;
+- pressure or inequalities in formations;
+- equipment failures or accidents;
+- adverse weather conditions;
+- compliance with governmental requirements; and
+- shortages or delays in the availability of drilling rigs and the
+delivery of equipment.
+6
+WE DO NOT OPERATE ALL OF OUR PROPERTIES AND HAVE LIMITED INFLUENCE OVER THE
+OPERATIONS OF SOME OF THESE PROPERTIES, PARTICULARLY OUR DEEPWATER PROPERTIES.
+Our lack of control could result in the following:
+- the operator may initiate exploration or development on a faster or
+slower pace than we prefer;
+- the operator may propose to drill more wells or build more
+facilities on a project than we have funds for or that we deem
+appropriate, which may mean that we are unable to participate in the
+project or share in the revenues generated by the project even
+though we paid our share of exploration costs; and
+- if an operator refuses to initiate a project, we may be unable to
+pursue the project.
+Any of these events could materially reduce the value of our properties.
+OUR DEEPWATER OPERATIONS HAVE SPECIAL OPERATIONAL RISKS THAT MAY NEGATIVELY
+AFFECT THE VALUE OF THOSE ASSETS. Drilling operations in the deepwater area are
+by their nature more difficult and costly than drilling operations in shallow
+water. Deepwater drilling operations require the application of more advanced
+drilling technologies involving a higher risk of technological failure and
+usually have significantly higher drilling costs than shallow water drilling
+operations. Deepwater wells are completed using sub-sea completion techniques
+that require substantial time and the use of advanced remote installation
+equipment. These operations involve a high risk of mechanical difficulties and
+equipment failures that could result in significant cost overruns.
+In deepwater, the time required to commence production following a discovery is
+much longer than in shallow water and on-shore. Our deepwater discoveries and
+prospects will require the construction of expensive production facilities and
+pipelines prior to the beginning of production. We cannot estimate the costs and
+timing of the construction of these facilities with certainty, and the accuracy
+of our estimates will be affected by a number of factors beyond our control,
+including the following:
+- decisions made by the operators of our deepwater wells;
+- the availability of materials necessary to construct the facilities;
+- the proximity of our discoveries to pipelines; and
+- the price of oil and natural gas.
+Delays and cost overruns in the commencement of production will affect the value
+of our deepwater prospects and the discounted present value of reserves
+attributable to those prospects.
+COMPETITIVE INDUSTRY CONDITIONS MAY NEGATIVELY AFFECT OUR ABILITY TO CONDUCT
+OPERATIONS. We operate in the highly competitive areas of oil and gas
+exploration, development and production. We compete for the purchase of leases
+in the Gulf of Mexico from the U. S. government and from other oil and gas
+companies. These leases include exploration prospects as well as properties with
+proved reserves. Factors that affect our ability to compete in the marketplace
+include:
+- our access to the capital necessary to drill wells and acquire
+properties;
+- our ability to acquire and analyze seismic, geological and other
+information relating to a property;
+- our ability to retain the personnel necessary to properly evaluate
+seismic and other information relating to a property;
+7
+- the location of, and our ability to access, platforms, pipelines and
+other facilities used to produce and transport oil and gas
+production;
+- the standards we establish for the minimum projected return on an
+investment of our capital; and
+- the availability of alternate fuel sources.
+Our competitors include major integrated oil companies, substantial independent
+energy companies, and affiliates of major interstate and intrastate pipelines
+and national and local gas gatherers, many of which possess greater financial,
+technological and other resources than we do.
+OUR COMPETITORS MAY USE SUPERIOR TECHNOLOGY, WHICH WE MAY BE UNABLE TO AFFORD OR
+WHICH WOULD REQUIRE COSTLY INVESTMENT BY US IN ORDER TO COMPETE. Our industry is
+subject to rapid and significant advancements in technology, including the
+introduction of new products and services using new technologies. As our
+competitors use or develop new technologies, we may be placed at a competitive
+disadvantage, and competitive pressures may force us to implement new
+technologies at a substantial cost. In addition, our competitors may have
+greater financial, technical and personnel resources that allow them to enjoy
+technological advantages and may in the future allow them to implement new
+technologies before we can. We cannot be certain that we will be able to
+implement technologies on a timely basis or at a cost that is acceptable to us.
+One or more of the technologies that we currently use or that we may implement
+in the future may become obsolete, and we may be adversely affected. For
+example, marine seismic acquisition technology has been characterized by rapid
+technological advancements in recent years, and further significant
+technological developments could substantially impair our 3-D seismic data's
+value.
+WE MAY NOT BE ABLE TO REPLACE OUR RESERVES OR GENERATE CASH FLOWS IF WE ARE
+UNABLE TO RAISE CAPITAL. WE WILL BE REQUIRED TO MAKE SUBSTANTIAL CAPITAL
+EXPENDITURES TO DEVELOP OUR EXISTING RESERVES, AND TO DISCOVER NEW OIL AND GAS
+RESERVES. Historically, we have financed these expenditures primarily with cash
+from operations, proceeds from bank borrowings and proceeds from the sale of
+debt and equity securities. See "Management's Discussion and Analysis of
+Financial Condition and Results of Operations -- Liquidity and Capital
+Resources" for a discussion of our capital budget. We cannot assure you that we
+will be able to raise capital in the future. We also make offers to acquire oil
+and gas properties in the ordinary course of our business. If these offers are
+accepted, our capital needs may increase substantially.
+We expect to continue using our senior secured credit facility to borrow funds
+to supplement our available cash. The amount we may borrow under our senior
+secured credit facility may not exceed a borrowing base determined by the
+lenders under such facility based on their projections of our future production,
+future production costs, taxes, commodity prices and any other factors deemed
+relevant by our lenders. We cannot control the assumptions the lenders use to
+calculate our borrowing base. The lenders may, without our consent, adjust the
+borrowing base semiannually or in situations where we purchase or sell assets or
+issue debt securities. If our borrowings under the senior secured credit
+facility exceed the borrowing base, the lenders may require that we repay the
+excess. If this were to occur, we might have to sell assets or seek financing
+from other sources. Sales of assets could further reduce the amount of our
+borrowing base. We cannot assure you that we would be successful in selling
+assets or arranging substitute financing. If we were not able to repay
+borrowings under our senior secured credit facility to reduce the outstanding
+amount to less than the borrowing base, we would be in default under our senior
+secured credit facility. For a description of our senior secured credit facility
+and its principal terms and conditions, see "Management's Discussion and
+Analysis of Financial Condition and Results of Operations --Liquidity and
+Capital Resources."
+OUR DECISION TO DRILL A PROSPECT IS SUBJECT TO A NUMBER OF FACTORS AND WE MAY
+DECIDE TO ALTER OUR DRILLING SCHEDULE OR NOT DRILL AT ALL. We describe our
+current prospects and our plans to explore these
+8
+prospects in this annual report. A prospect is a property on which we have
+identified what our geoscientists believe, based on available seismic and
+geological information, to be indications of hydrocarbons. Our prospects are in
+various stages of evaluation, ranging from a prospect which is ready to drill to
+a prospect which will require substantial additional seismic data processing and
+interpretation. Whether we ultimately drill a prospect may depend on the
+following factors:
+- receipt of additional seismic data or the reprocessing of existing
+data;
+- material changes in oil or gas prices;
+- the costs and availability of drilling rigs;
+- the success or failure of wells drilled in similar formations or
+which would use the same production facilities;
+- availability and cost of capital;
+- changes in the estimates of the costs to drill or complete wells;
+- our ability to attract other industry partners to acquire a portion
+of the working interest to reduce exposure to costs and drilling
+risks; and
+- decisions of our joint working interest owners.
+We will continue to gather data about our prospects and it is possible that
+additional information may cause us to alter our drilling schedule or determine
+that a prospect should not be pursued at all. You should understand that our
+plans regarding our prospects are subject to change.
+WEATHER, UNEXPECTED SUBSURFACE CONDITIONS, AND OTHER UNFORESEEN OPERATING
+HAZARDS MAY ADVERSELY IMPACT OUR ABILITY TO CONDUCT BUSINESS. There are many
+operating hazards in exploring for and producing oil and gas, including:
+- our drilling operations may encounter unexpected formations or
+pressures, which could cause damage to equipment or personal injury;
+- we may experience equipment failures which curtail or stop
+production; and
+- we could experience blowouts or other damages to the productive
+formations that may require a well to be re-drilled or other
+corrective action to be taken.
+In addition, any of the foregoing may result in environmental damages for which
+we will be liable. Moreover, a substantial portion of our operations are
+offshore and are subject to a variety of risks peculiar to the marine
+environment such as capsizing, collisions, hurricanes and other adverse weather
+conditions. These conditions can cause substantial damage to facilities and
+interrupt production. Offshore operations are also subject to more extensive
+governmental regulation.
+We cannot assure you that we will be able to maintain adequate insurance at
+rates we consider reasonable to cover our possible losses from operating
+hazards. The occurrence of a significant event not fully insured or indemnified
+against could materially and adversely affect our financial condition and
+results of operations.
+WE MAY NOT HAVE PRODUCTION TO OFFSET HEDGES; BY HEDGING, WE MAY NOT BENEFIT FROM
+PRICE INCREASES. Part of our business strategy is to reduce our exposure to the
+volatility of oil and gas prices by hedging a portion of our production. In a
+typical hedge transaction, we will have the right to receive from the other
+parties to the hedge the excess of the fixed price specified in the hedge over a
+floating price based on a market index, multiplied by the quantity hedged. If
+the floating price exceeds the fixed price, we are required to pay the other
+parties this difference multiplied by the quantity hedged. We are required to
+pay the difference between the floating price and the fixed price when the
+floating price exceeds the fixed
+9
+price regardless of whether we have sufficient production to cover the
+quantities specified in the hedge. Significant reductions in production at times
+when the floating price exceeds the fixed price could require us to make
+payments under the hedge agreements even though such payments are not offset by
+sales of production. Hedging will also prevent us from receiving the full
+advantage of increases in oil or gas prices above the fixed amount specified in
+the hedge. We also enter into price "collars" to reduce the risk of changes in
+oil and gas prices. Under a collar, no payments are due by either party so long
+as the market price is above a floor set in the collar and below a ceiling. If
+the price falls below the floor, the counter-party to the collar pays the
+difference to us and if the price is above the ceiling, we pay the counter-party
+the difference. See "Quantitative and Qualitative Disclosures About Market
+Risks" for a discussion of our hedging practices.
+COMPLIANCE WITH ENVIRONMENTAL AND OTHER GOVERNMENT REGULATIONS COULD BE COSTLY
+AND COULD NEGATIVELY IMPACT PRODUCTION. Our operations are subject to numerous
+laws and regulations governing the operation and maintenance of our facilities
+and the discharge of materials into the environment or otherwise relating to
+environmental protection. For a discussion of the material regulations
+applicable to us, see "Federal Regulations," "State Regulations," and
+"Environmental Regulations." These laws and regulations may:
+- require that we acquire permits before commencing drilling;
+- restrict the substances that can be released into the environment in
+connection with drilling and production activities;
+- limit or prohibit drilling activities on protected areas such as
+wetlands or wilderness areas; and
+- require remedial measures to mitigate pollution from former
+operations, such as dismantling abandoned production facilities.
+Under these laws and regulations, we could be liable for personal injury and
+clean-up costs and other environmental and property damages, as well as
+administrative, civil and criminal penalties. We maintain limited insurance
+coverage for sudden and accidental environmental damages. We do not believe that
+insurance coverage for environmental damages that occur over time is available
+at a reasonable cost. Also, we do not believe that insurance coverage for the
+full potential liability that could be caused by sudden and accidental
+environmental damages is available at a reasonable cost. Accordingly, we may be
+subject to liability or we may be required to cease production from properties
+in the event of environmental damages.
+FACTORS BEYOND OUR CONTROL AFFECT OUR ABILITY TO MARKET PRODUCTION AND OUR
+FINANCIAL RESULTS. The ability to market oil and gas from our wells depends upon
+numerous factors beyond our control. These factors include:
+- the extent of domestic production and imports of oil and gas;
+- the proximity of the gas production to gas pipelines;
+- the availability of pipeline capacity;
+- the demand for oil and gas by utilities and other end users;
+- the availability of alternative fuel sources;
+- the effects of inclement weather;
+- state and federal regulation of oil and gas marketing; and
+- federal regulation of gas sold or transported in interstate
+commerce.
+10
+Because of these factors, we may be unable to market all of the oil or gas we
+produce. In addition, we may be unable to obtain favorable prices for the oil
+and gas we produce.
+IF OIL AND GAS PRICES DECREASE, WE MAY BE REQUIRED TO TAKE WRITEDOWNS OF THE
+CARRYING VALUE OF OUR OIL AND GAS PROPERTIES. We may be required to writedown
+the carrying value of our oil and gas properties when oil and gas prices are low
+or if we have substantial downward adjustments to our estimated net proved
+reserves, increases in our estimates of development costs or deterioration in
+our exploration results. Under the full cost method which we use to account for
+our oil and gas properties, the net capitalized costs of our oil and gas
+properties may not exceed the present value, discounted at 10%, of future net
+cash flows from estimated net proved reserves, using period end oil and gas
+prices or prices as of the date of our auditor's report, plus the lower of cost
+or fair market value of our unproved properties. If net capitalized costs of our
+oil and gas properties exceed this limit, we must charge the amount of the
+excess to earnings. This type of charge will not affect our cash flows, but will
+reduce the book value of our stockholders' equity. We review the carrying value
+of our properties quarterly, based on prices in effect as of the end of each
+quarter or at the time of reporting our results. Once incurred, a writedown of
+oil and gas properties is not reversible at a later date, even if prices
+increase.
+FORWARD-LOOKING STATEMENTS
+In this report, we have made many forward-looking statements. We cannot assure
+you that the plans, intentions or expectations upon which our forward-looking
+statements are based will occur. Our forward-looking statements are subject to
+risks, uncertainties and assumptions, including those discussed elsewhere in
+this report. Forward-looking statements include statements regarding:
+- our oil and gas reserve quantities, and the discounted present value
+of these reserves;
+- the amount and nature of our capital expenditures;
+- drilling of wells;
+- the timing and amount of future production and operating costs;
+- business strategies and plans of management; and
+- prospect development and property acquisitions.
+Some of the risks, which could affect our future results and could cause results
+to differ materially from those expressed in our forward-looking statements
+include:
+- general economic conditions;
+- the volatility of oil and natural gas prices;
+- the uncertainty of estimates of oil and natural gas reserves;
+- the impact of competition;
+- the availability and cost of seismic, drilling and other equipment;
+- operating hazards inherent in the exploration for and production of
+oil and natural gas;
+- difficulties encountered during the exploration for and production
+of oil and natural gas;
+- difficulties encountered in delivering oil and natural gas to
+commercial markets;
+- changes in customer demand and producers' supply;
+- the uncertainty of our ability to attract capital;
+- compliance with, or the effect of changes in, the extensive
+governmental regulations regarding the oil and natural gas business;
+- actions of operators of our oil and gas properties; and
+- weather conditions.
+11
+The information contained in this report, including the information set forth
+under the heading "Risk Factors," identifies additional factors that could
+affect our operating results and performance. We urge you to carefully consider
+these factors and the other cautionary statements in this report. Our
+forward-looking statements speak only as of the date made, and we have no
+obligation to update these forward-looking statements.
+CORPORATE OFFICES
+Our headquarters are located in Natchez, Mississippi, in approximately 51,500
+square feet of owned space, with a field office in Houston, Texas. We also
+maintain owned or leased field offices in the area of the major fields in which
+we operate properties or have a significant interest. Replacement of any of our
+leased offices would not result in material expenditures by us as alternative
+locations to our leased space are anticipated to be readily available.
+EMPLOYEES
+We had 94 employees as of December 31, 2003, none of whom are currently
+represented by a union. We believe that we have good relations with our
+employees. We employ eight petroleum engineers and seven petroleum
+geoscientists.
+FEDERAL REGULATIONS
+SALES OF NATURAL GAS. Effective January 1, 1993, the Natural Gas Wellhead
+Decontrol Act deregulated prices for all "first sales" of natural gas. Thus, all
+sales of gas by us may be made at market prices, subject to applicable contract
+provisions.
+TRANSPORTATION OF NATURAL GAS. The rates, terms and conditions applicable to the
+interstate transportation of natural gas by pipelines are regulated by the
+Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act ("NGA"),
+as well as under section 311 of the Natural Gas Policy Act ("NGPA"). Since 1985,
+the FERC has implemented regulations intended to make natural gas transportation
+more accessible to gas buyers and sellers on an open-access, non-discriminatory
+basis.
+In February, 2000, the FERC issued Order No. 637, a final rule designed to
+continue the restructuring of the gas industry initiated by an earlier final
+rule, Order No. 636, that instituted "open access" transportation. Order No. 637
+further revised the FERC's policies governing interstate pipeline transportation
+rates and penalties and further refined the regulatory framework governing
+transportation terms and conditions to improve open access transportation. The
+rule has been implemented on a pipeline-by-pipeline basis in individual
+compliance proceedings, many of which have been settled or have otherwise been
+terminated. A few proceedings, however, are still pending final resolution.
+In Order No. 644 issued November 13, 2003, the FERC imposed new standards of
+conduct, inter alia, for "all sellers for resale" marketing gas under blanket
+market certificates. The standards include a requirement of accurate reporting,
+if any, of the price of arm's-length deals to price index publishers and a
+requirement to notify the FERC as to whether the marketer reports transactions
+to price index publishers. In Order No. 2004, issued on November 25, 2003, the
+FERC issued standards of conduct covering regulated interstate pipelines and
+public utilities ("Transmission Providers") to govern the relationships between
+regulated Transmission Providers and all of their energy affiliates. Among other
+things, these measures are intended to
+12
+increase confidence and transparency in the gas market in the wake of recent
+events involving anticompetitive behavior and market abuse.
+On February 12, 2004, the FERC issued a notice of proposed rulemaking in Docket
+No. RM04-4 designed to standardize the procedures for determining the
+creditworthiness of shippers on interstate pipelines and to adopt certain
+standards published by the North American Energy Standards Board with respect to
+shipper creditworthiness. The standards are intended to facilitate and increase
+transparency in the creditworthiness evaluation process.
+The FERC is presently reviewing in Docket No. PL04-3 whether it should adopt
+standards for "interchangeability" of natural gas, that is, whether it should
+standardize the composition and quality of natural gas transported through the
+delivery system, including interstate pipelines. Although the standards, if any,
+are likely to be voluntary, at the present time the approach that the FERC will
+take and the potential impact on gas supply are not clear.
+With respect to the transportation of natural gas on or across the Outer
+Continental Shelf ("OCS"), the FERC requires, as part of its regulation under
+the Outer Continental Shelf Lands Act ("OCSLA"), that all pipelines provide open
+and non-discriminatory access to both owner and non-owner shippers. Although to
+date the FERC has imposed light-handed regulation on off-shore facilities that
+meet its traditional test of gathering status, it has the authority to exercise
+jurisdiction under the OCSLA over gathering facilities, if necessary, to permit
+non-discriminatory access to service. In an effort to heighten its oversight of
+the OCS, the FERC recently attempted to promulgate reporting requirements for
+all OCS "service providers," including gatherers, but the regulations were
+struck down as ultra vires by a federal district court in October, 2003. In
+addition, the FERC recently reasserted NGA jurisdiction over certain offshore
+gathering facilities over which it had previously disclaimed jurisdiction where
+it determined that the FERC's open access regulatory regime was being frustrated
+by an interstate pipeline in concert with an affiliated gathering company. For
+those facilities transporting natural gas across the OCS that are not considered
+to be gathering facilities, the rates, terms, and conditions applicable to this
+transportation are regulated by the FERC under the NGA and NGPA, as well as the
+OCSLA.
+SALES AND TRANSPORTATION OF CRUDE OIL. Sales of crude oil and condensate can be
+made by us at market prices not subject at this time to price controls. The
+price that we receive from the sale of these products will be affected by the
+cost of transporting the products to market. The rates, terms, and conditions
+applicable to the interstate transportation of oil and related products by
+pipelines are regulated by the FERC under the Interstate Commerce Act. Pursuant
+to the Energy Policy Act of 1992, which "grandfathered" certain existing rates,
+the FERC presently regulates oil pipeline rates under a light-handed,
+streamlined regulatory regime where rates are adjusted annually using an index
+ceiling based upon the producer price index. The FERC recently modified the
+formula for calculating the index such that the index ceilings are now set
+slightly higher than in their original iteration. As an exception to indexing,
+the FERC will also, under defined circumstances, permit alternative ratemaking
+methodologies for interstate oil pipelines such as the use of cost of service
+rates, settlement rates, and market-based rates. Market-based rates will be
+permitted to the extent the pipeline can demonstrate that it lacks significant
+market power in the market in which it proposes to charge market-based rates.
+The cumulative effect that these rules have had on moving our production to
+market have not been material.
+With respect to the transportation of oil and condensate on or across the OCS,
+the FERC requires, as part of its regulation under the OCSLA, that all pipelines
+provide open and non-discriminatory access to both owner and non-owner shippers.
+Accordingly, the FERC has the authority to exercise jurisdiction under the
+OCSLA, if necessary, to permit non-discriminatory access to service.
+13
+LEGISLATIVE PROPOSALS. In the past, Congress has been very active in the area of
+natural gas regulation. There are legislative proposals pending in Congress and
+in various state legislatures which, if enacted, could significantly affect the
+petroleum industry. At the present time it is difficult to predict what
+proposals, if any, might actually be enacted by Congress or the various state
+legislatures and what effect, if any, such proposals might have on our
+operations.
+FEDERAL, STATE OR INDIAN LEASES. In the event we conduct operations on federal,
+state or Indian oil and gas leases, such operations must comply with numerous
+regulatory restrictions, including various nondiscrimination statutes, royalty
+and related valuation requirements, and certain of such operations must be
+conducted pursuant to on-site security regulations and other appropriate permits
+issued by the Bureau of Land Management ("BLM") or Minerals Management Service
+("MMS") or other appropriate federal or state agencies.
+The Company's OCS leases in federal waters are administered by the MMS and
+require compliance with detailed MMS regulations and orders. The MMS has
+promulgated regulations implementing restrictions on various production-related
+activities, including restricting the flaring or venting of natural gas. Under
+certain circumstances, the MMS may require our operations on federal leases to
+be suspended or terminated. Any such suspension or termination could materially
+and adversely affect our financial condition and operations. On March 15, 2000,
+the MMS issued a final rule effective June 1, 2000 which amends its regulations
+governing the calculation of royalties and the valuation of crude oil produced
+from federal leases. Among other matters, this rule amends the valuation
+procedure for the sale of federal royalty oil by eliminating posted prices as a
+measure of value and relying instead on arm's length sales prices and spot
+market prices as market value indicators. Because we sell our production in the
+spot market and therefore pay royalties on production from federal leases, it is
+not anticipated that this final rule will have any substantial impact on us.
+The Mineral Leasing Act of 1920 ("Mineral Act") prohibits direct or indirect
+ownership of any interest in federal onshore oil and gas leases by a foreign
+citizen of a country that denies "similar or like privileges" to citizens of the
+United States. Such restrictions on citizens of a "non-reciprocal" country
+include ownership or holding or controlling stock in a corporation that holds a
+federal onshore oil and gas lease. If this restriction is violated, the
+corporation's lease can be canceled in a proceeding instituted by the United
+States Attorney General. Although the regulations of the BLM (which administers
+the Mineral Act) provide for agency designations of non-reciprocal countries,
+there are presently no such designations in effect. We own interests in numerous
+federal onshore oil and gas leases. It is possible that some of our stockholders
+may be citizens of foreign countries, which at some time in the future might be
+determined to be non-reciprocal under the Mineral Act.
+STATE REGULATIONS
+Most states regulate the production and sale of oil and natural gas, including
+requirements for obtaining drilling permits, the method of developing new
+fields, the spacing and operation of wells and the prevention of waste of oil
+and gas resources. The rate of production may be regulated and the maximum daily
+production allowable from both oil and gas wells may be established on a market
+demand or conservation basis or both.
+We may enter into agreements relating to the construction or operation of a
+pipeline system for the transportation of natural gas. To the extent that such
+gas is produced, transported and consumed wholly within one state, such
+operations may, in certain instances, be subject to the jurisdiction of such
+state's administrative authority charged with the responsibility of regulating
+intrastate pipelines. In such event, the
+14
+rates which we could charge for gas, the transportation of gas, and the costs of
+construction and operation of such pipeline would be impacted by the rules and
+regulations governing such matters, if any, of such administrative authority.
+Further, such a pipeline system would be subject to various state and/or federal
+pipeline safety regulations and requirements, including those of, among others,
+the Department of Transportation. Such regulations can increase the cost of
+planning, designing, installing and operating such facilities. The impact of
+such pipeline safety regulations would not be any more adverse to us than it
+would be to other similar owners or operators of such pipeline facilities.
+ENVIRONMENTAL REGULATIONS
+GENERAL. Our activities are subject to federal, state and local laws and
+regulations governing environmental quality and pollution control. Although no
+assurances can be made, we believe that, absent the occurrence of an
+extraordinary event, compliance with existing federal, state and local laws,
+rules and regulations regulating the release of materials into the environment
+or otherwise relating to the protection of the environment will not have a
+material effect upon our capital expenditures, earnings or competitive position
+with respect to our existing assets and operations. We cannot predict what
+effect future regulation or legislation, enforcement policies, and claims for
+damages to property, employees, other persons and the environment resulting from
+our operations could have on our activities.
+Our activities with respect to natural gas facilities, including the operation
+and construction of pipelines, plants and other facilities for transporting,
+processing, treating or storing natural gas and other products, are subject to
+stringent environmental regulation by state and federal authorities including
+the United States Environmental Protection Agency ("EPA"). Such regulation can
+increase the cost of planning, designing, installing and operating such
+facilities. In most instances, the regulatory requirements relate to water and
+air pollution control measures. Although we believe that compliance with
+environmental regulations will not have a material adverse effect on us, risks
+of substantial costs and liabilities are inherent in oil and gas production
+operations, and there can be no assurance that significant costs and liabilities
+will not be incurred. Moreover, it is possible that other developments, such as
+stricter environmental laws and regulations, and claims for damages to property
+or persons resulting from oil and gas production, would result in substantial
+costs and liabilities to us.
+SOLID AND HAZARDOUS WASTE. We currently own or lease, and in the past owned or
+leased, properties that have been used for the exploration and production of oil
+and gas for many years. Although we have utilized operating and disposal
+practices that were standard in the industry at the time, hydrocarbons or other
+solid wastes may have been disposed or released on or under the properties owned
+or leased by us or on or under locations where such wastes have been taken for
+disposal. In addition, many of these properties have been operated by third
+parties. We have no control over such entities' treatment of hydrocarbons or
+other solid wastes and the manner in which such substances may have been
+disposed or released. State and federal laws applicable to oil and gas wastes
+and properties have gradually become stricter over time. Under new laws, we
+could be required to remediate property, including groundwater, containing or
+impacted by previously disposed wastes (including wastes disposed or released by
+prior owners or operators, or property contamination, including groundwater
+contamination by prior owners or operators) or to perform remedial plugging
+operations to prevent future or mitigate existing contamination.
+We generate wastes, including hazardous wastes that are subject to the federal
+Resource Conservation and Recovery Act ("RCRA") and comparable state statutes.
+The EPA and various state agencies have limited the disposal options for certain
+wastes, including wastes designated as hazardous under the RCRA and similar
+state statutes ("Hazardous Wastes"). Furthermore, it is possible that certain
+wastes generated by our oil and gas operations that are (currently exempt from
+treatment as) Hazardous Wastes may in the future be
+15
+designated as Hazardous Wastes under RCRA or other applicable statutes and,
+therefore, may be subject to more rigorous and costly disposal requirements.
+SUPERFUND. The federal Comprehensive Environmental Response, Compensation and
+Liability Act ("CERCLA"), also known as the "Superfund" law, generally imposes
+joint and several liability for costs of investigation and remediation and for
+natural resource damages, without regard to fault or the legality of the
+original conduct, on certain classes of persons with respect to the release into
+the environment of substances designated under CERCLA as hazardous substances
+("Hazardous Substances"). These classes of persons, or so-called potentially
+responsible parties ("PRPs"), include the current and certain past owners and
+operators of a facility where there has been a release or threat of release of a
+Hazardous Substance and persons who disposed of or arranged for the disposal of
+Hazardous Substances found at a site. CERCLA also authorizes the EPA and, in
+some cases, third parties to take actions in response to threats to the public
+health or the environment and to seek to recover from the PRPs the costs of such
+action. Although CERCLA generally exempts "petroleum" from the definition of
+Hazardous Substance, in the course of its operations, we have generated and will
+generate wastes that may fall within CERCLA's definition of Hazardous Substance.
+We may also be the owner or operator of sites on which Hazardous Substances have
+been released. To our knowledge, neither we nor our predecessors have been
+designated as a PRP by the EPA under CERCLA. We also do not know of any prior
+owners or operators of our properties that are named as PRPs related to their
+ownership or operation of such properties.
+CLEAN WATER ACT. The Clean Water Act ("CWA") imposes restrictions and strict
+controls regarding the discharge of wastes including produced waters and other
+oil and natural gas wastes, into waters of the United States, a term broadly
+defined. These controls have become more stringent over the years, and it is
+probable that additional restrictions will be imposed in the future. Permits
+must be obtained to discharge pollutants into federal waters. The CWA provides
+for civil, criminal and administrative penalties for unauthorized discharges of
+oil and hazardous substances and of other pollutants. It imposes substantial
+potential liability for the costs of removal or remediation associated with
+discharges of oil or hazardous substances and other pollutants. State laws
+governing discharges to water also provide varying civil, criminal and
+administrative penalties and impose liabilities in the case of a discharge of
+petroleum or its derivatives, or other hazardous substances, into state waters.
+In addition, the EPA has promulgated regulations that may require us to obtain
+permits to discharge storm water runoff, including discharges associated with
+construction activities. In the event of an unauthorized discharge of wastes, we
+may be liable for penalties and costs.
+OIL POLLUTION ACT. The Oil Pollution Act of 1990 ("OPA"), which amends and
+augments oil spill provisions of the CWA, imposes certain duties and liabilities
+on certain "responsible parties" related to the prevention of oil spills and
+damages resulting from such spills in or threatening United States waters or
+adjoining shorelines. A liable "responsible party" includes the owner or
+operator of a facility, vessel or pipeline that is a source of an oil discharge
+or that poses the substantial threat of discharge, or the lessee or permittee of
+the area in which a discharging facility is located. The OPA assigns joint and
+several liability, without regard to fault, to each liable party for oil removal
+costs and a variety of public and private damages. Although defenses and
+limitations exist to the liability imposed by OPA, they are limited. In the
+event of an oil discharge or substantial threat of discharge, we may be liable
+for costs and damages.
+The OPA also imposes ongoing requirements on a responsible party, including
+proof of financial responsibility to cover at least some costs in a potential
+spill. Certain amendments to the OPA that were enacted in 1996 require owners
+and operators of offshore facilities that have a worst case oil spill potential
+of more than 1,000 barrels to demonstrate financial responsibility in amounts
+ranging from $10 million in specified state waters and $35 million in federal
+OCS waters, with higher amounts, up to $150 million based
+16
+upon worst case oil-spill discharge volume calculations. We believe that we have
+established adequate proof of financial responsibility for our offshore
+facilities.
+AIR EMISSIONS. Our operations are subject to local, state and federal
+regulations for the control of emissions from sources of air pollution. Federal
+and state laws require new and modified sources of air pollutants to obtain
+permits prior to commencing construction. Major sources of air pollutants are
+subject to more stringent, federally imposed requirements including additional
+permits. Federal and state laws designed to control hazardous (toxic) air
+pollutants, might require installation of additional controls. Administrative
+enforcement actions for failure to comply strictly with air pollution
+regulations or permits are generally resolved by payment of monetary fines and
+correction of any identified deficiencies. Alternatively, regulatory agencies
+could bring lawsuits for civil penalties or require us to forego construction,
+modification or operation of certain air emission sources.
+COASTAL COORDINATION. There are various federal and state programs that regulate
+the conservation and development of coastal resources. The federal Coastal Zone
+Management Act ("CZMA") was passed in 1972 to preserve and, where possible,
+restore the natural resources of the Nation's coastal zone. The CZMA provides
+for federal grants for state management programs that regulate land use, water
+use and coastal development.
+Various states, such as Alabama, Louisiana and Texas, also have coastal
+management programs, which provide for, among other things, the coordination
+among local and state authorities to protect coastal resources through
+regulating land use, water, and coastal development. Coastal management programs
+also may provide for the review of state and federal agency rules and agency
+actions for consistency with the goals and policies of the state coastal
+management plan. This review may impact agency permitting and review activities
+and add an additional layer of review to certain activities undertaken by us.
+OSHA AND OTHER REGULATIONS. We are subject to the requirements of the federal
+Occupational Safety and Health Act ("OSHA") and comparable state statutes. The
+OSHA hazard communication standard, the EPA community right-to-know regulations
+under Title III of CERCLA and similar state statutes require us to organize
+and/or disclose information about hazardous materials used or produced in its
+operations.
+Our management believes that we are in substantial compliance with current
+applicable environmental laws and regulations and that continued compliance with
+existing requirements would not have a material adverse impact on us.
+PROPERTY SUMMARY
+We are engaged in the exploration, development, acquisition and production of
+oil and gas properties and provide oil and gas property management services for
+other investors. Our properties are concentrated offshore in the Gulf of Mexico
+and onshore, primarily, in Louisiana and Alabama. We have historically grown our
+reserves and production by focusing primarily on low to moderate risk
+exploration and acquisition opportunities in the Gulf of Mexico shelf area. Over
+the last several years, we have expanded our area of exploration to include the
+Gulf of Mexico deepwater area. As of December 31, 2003, our estimated net proved
+reserves totaled 23.7 million barrels of oil ("MBbl") and 74.7 billion cubic
+feet of natural gas ("Bcf"), with a pre-tax present value, discounted at 10%, of
+the estimated future net revenues based on constant prices in effect at year-end
+("Discounted Cash Flow") of $570.5 million. Gas constitutes approximately 34% of
+our total estimated proved reserves and approximately 42% of our total estimated
+proved reserves are proved developed reserves.
+17
+Our Medusa (Mississippi Canyon Blocks 538/582) and Habanero (Garden Banks Block
+341) discoveries began production in the fourth quarter of 2003. These two
+deepwater discoveries are expected to increase our projected 2004 production by
+approximately 85% from 2003 levels. A detail discussion of each of these
+properties is provided in the "Significant Properties" section of this report.
+SIGNIFICANT PROPERTIES
+The following table shows discounted cash flows and estimated net proved oil and
+gas reserves by major field, within the focus area, for our seven largest fields
+and for all other properties combined at December 31, 2003.
+ESTIMATED NET PROVED RESERVES PRE-TAX
+------------------------------ DISCOUNTED
+OIL GAS TOTAL PRESENT VALUE
+OPERATOR (MBBLS) (MMCF) (MMCFE) ($000)
+-------- -------- -------- -------- -------------
+(A)(B)
+GULF OF MEXICO DEEPWATER:
+Mississippi Canyon Blocks 538/582
+"Medusa" Murphy 10,312 6,173 68,043 $160,297
+Garden Banks Block 341
+"Habanero" Shell 4,687 11,207 39,328 124,876
+Garden Banks Blocks 738/782/826/827
+"Entrada" BP Amoco 7,772 29,126 75,760 185,608
+GULF OF MEXICO SHELF:
+Mobile Blocks 863/864/907/908 Callon -- 4,873 4,873 15,641
+Mobile Blocks 952/953/955 Callon -- 15,229 15,229 60,487
+Ship Shoal Blocks 28/35 Callon 6 701 739 3,115
+ONSHORE AND OTHER:
+Big Escambia Creek Exxon 422 1,188 3,718 6,116
+Other Various 510 6,194 9,253 14,323
+-------- -------- -------- --------
+TOTAL NET PROVED RESERVES 23,709 74,691 216,943 $570,463
+======== ======== ======== ========
+(a) Represents the present value of future net cash flows before deduction of
+federal income taxes, discounted at 10%, attributable to estimated net
+proved reserves as of December 31, 2003, as set forth in the Company's
+reserve reports prepared by its independent petroleum reserve engineers,
+Huddleston & Co., Inc. of Houston, Texas.
+(b) Includes a reduction for estimated plugging and abandonment costs that is
+reflected as a liability on our balance sheet at December 31, 2003, in
+accordance with Statement of Financial Accounting Standards No. 143.
+18
+GULF OF MEXICO DEEPWATER
+Medusa, Mississippi Canyon Blocks 538/582
+Our Medusa deepwater discovery was announced in September 1999, when we drilled
+the initial test well in 2,235 feet of water to a total depth of 16,241 feet and
+encountered over 120 feet of pay in two intervals. Subsequent sidetrack drilling
+from the wellbore was used to determine the extent of the discovery and a second
+successful well was drilled in the first quarter of 2000 to further delineate
+the extent of the pay intervals. We own a 15% working interest, Murphy, the
+operator, owns a 60% working interest and Agip Ventures, formerly British-Borneo
+Petroleum, Inc., owns the remaining 25% working interest.
+In 2001 a drilling program began which included four development wells and one
+sidetrack. The program included production casing being set on six wells to
+provide initial production take-points. The program was completed in the first
+half of 2002. Also in 2001, the operator submitted an Authorization for
+Expenditure for a floating production system, spar, at Medusa and awarded the
+contract to J. Ray McDermott, Inc. The spar hull was barged to Mississippi
+Canyon Block 582 during the first quarter of 2003, uprighted, moored and placed
+in position to receive the production deck. The topside deck and production
+facilities were delivered and lifted into place atop the spar hull during the
+second quarter of 2003. The A-1 well, the first of six, was completed and tied
+into the spar and commenced production in late November 2003. The A-2 well
+commenced production in January 2004 and during February 2004 the field produced
+approximately 19,000 barrels of oil and 18 million cubic feet of gas per day.
+Initial production from the A-3 well is expected during March 2004 and will be
+followed by initial production from the A-6 and A-4 wells in the second quarter
+of 2004 with production from the A-5 well expected early in the 3rd quarter of
+2004. Peak production from the field is expected to reach approximately 40,000
+barrels of crude oil and 35 million cubic feet of natural gas per day.
+In December 2003, we transferred our undivided 15% working interest in the spar
+production facilities to Medusa Spar LLC in exchange for cash proceeds of
+approximately $25 million and a 10% ownership interest in the LLC. A detailed
+discussion of this transaction is included in Management's Discussion and
+Analysis of Financial Condition and Results of Operations-"Off-Balance Sheet
+Arrangements".
+Habanero, Garden Banks Block 341
+During February 1999 the initial test well on our Habanero deepwater discovery
+encountered over 200 feet of net pay in two zones. Located in 2,000 feet of
+water, the well was drilled to a measured depth of 21,158 feet. We own an 11.25%
+working interest in the well. The well is operated by Shell Deepwater
+Development Inc., which owns a 55% working interest, with the remaining working
+interest being owned by Murphy.
+A field delineation program began in mid-year 2001, which included three
+sidetracks of the discovery well. Production casing was set on this well through
+one of the sidetracks to the Habanero 52 oil and gas sand and the Habanero 55
+gas sand. Initial production will be from the Habanero 55 gas sand and future
+recompletions are scheduled up-hole to the Habanero 52 oil and gas sand. Also, a
+development well was drilled in the summer of 2003 which provides a take-point
+for production from the Habanero 52 oil sand.
+19
+By means of a sub-sea completion and tie back to an existing production facility
+in the area operated by Shell, production from the Habanero 52 oil sand
+commenced in late November 2003. Production from the Habanero 55 gas sand
+commenced in January, after mechanical adjustments were made down hole. Gross
+production during February 2003 from the Habanero field was approximately 22,000
+barrels of oil and 56 million cubic feet of gas per day.
+Entrada, Garden Banks Blocks 738/782/826/827
+The Entrada discovery is located in approximately 4,500 feet of water in the
+Gulf of Mexico. Two wells and seven sidetracks have been drilled to date on
+Garden Banks 782 on a northwest plunging salt ridge along the southern edge of
+the Entrada Basin. Multiple stacked amplitudes trapped against a salt or fault
+interface characterize the Entrada Area. We own a 20% working interest in this
+discovery with BP Amoco, the operator, holding the remaining working interest.
+The owners of an adjacent discovery have announced their plans to construct
+production facilities to enable them to be a regional off-take point in
+Southeastern Garden Banks. These plans include handling third party tie-ins. We
+expect to tie-in Entrada to this regional off-take point with initial production
+anticipated in 2006. First production from the adjacent discovery is expected in
+late 2004. Information obtained in a data swap with the adjacent owners is being
+incorporated into the Entrada development plans. An integrated project team was
+formed by the working interest owners during 2002 to begin planning the
+development of the field. The team has been reviewing alternate development
+plans which could accelerate field development.
+GULF OF MEXICO SHELF
+Mobile Blocks 863/864/ 907/908
+We own an average 67.9% working interest in these blocks and we are the
+operator. The Mobile 864 unit, in which we have a 66.4% working interest, has
+three producing wells, unit production facilities and covers portions of these
+four blocks. During 2003 the unit produced an average of 4.9 MMcf per day net to
+us.
+Mobile Blocks 952/953/955
+We own a 100% working interest in these three blocks and we are the operator. In
+the fourth quarter of 2001, we initiated a production acceleration program for
+Mobile Blocks 952, 953 and 955, which were being produced through the Mobile
+Block 864 unit facilities. An acceleration well was successfully drilled in the
+fourth quarter of 2001 and stand-alone production facilities were installed and
+production flow lines were rerouted to the new facilities. Production commenced
+through the new facilities in April 2002. In order to completely produce the
+proved reserves of the field we drilled a development well on Mobile Block 955
+during the first quarter of 2004. The well is flowing without compression and
+commenced production in March 2004 at a gross rate of approximately 8 MMcf per
+day. The installation of compression facilities at the well site is expected to
+be completed by June 2004 and should increase the production rate by an
+additional 2-3 MMcf per day. Production from the field for 2003 was 19.6 MMcf
+per day net to us. Production for 2002 was 14.0 MMcf per day net to us.
+20
+Ship Shoal Blocks 28/35
+We successfully drilled an exploratory well at Ship Shoal Blocks 28 and 35
+during the third quarter of 2002. The well was drilled to a measured depth of
+15,237 feet (12,295 feet of true vertical depth) and encountered 140 feet of net
+natural gas pay. The well was completed as a single producer in the deepest of
+three productive intervals and first production commenced in late April, 2003
+and averaged 1.7 MMcfe per day net to us through December 31, 2003. We operate
+and own a 22% working interest.
+ONSHORE AND OTHER
+Big Escambia Creek
+This gas field in south Alabama produces from the Smackover formation at depths
+ranging from 15,100 to 15,600 feet and is operated by ExxonMobil. We own an
+average working interest of 4.9% (5.5% net revenue interest), in six wells and a
+2.2% average royalty interest in another five wells. This field produced 0.7
+MMcfe per day to our interest in 2003. The field has an estimated reserve life
+in excess of 10 years given current production rates.
+Other
+We own various royalty and working interests in numerous onshore areas and the
+Gulf of Mexico other than the fields discussed above.
+21
+OIL AND GAS RESERVES
+The following table sets forth certain information about our estimated proved
+reserves as of the dates set forth below.
+YEARS ENDED DECEMBER 31,
+---------------------------------
+2003 2002(a) 2001(a)
+--------- --------- ---------
+(IN THOUSANDS)
+Proved developed:
+Oil (Bbls) 9,919 1,056 885
+Gas (Mcf) 31,415 37,631 52,375
+Mcfe 90,926 43,966 57,683
+Proved undeveloped:
+Oil (Bbls) 13,790 22,988 29,324
+Gas (Mcf) 43,276 53,908 69,078
+Mcfe 126,017 191,833 245,023
+Total proved:
+Oil (Bbls) 23,709 24,043 30,209
+Gas (Mcf) 74,691 91,539 121,453
+Mcfe 216,943 235,799 302,706
+Estimated pre-tax future net cash flows(b) $ 838,847 $ 970,198 $ 473,896
+========= ========= =========
+Pre-tax discounted present value (b) $ 570,463 $ 623,946 $ 272,053
+========= ========= =========
+Standardized measure of discounted future
+net cash flows(b) $ 519,026 $ 556,046 $ 254,857
+========= ========= =========
+(a) The estimates include reserve volumes of approximately 1.2 Bcf, $2.9
+million of pre-tax discounted present value in 2001, attributable to
+a volumetric production payment. Standardized measure of discounted
+future net cash flows does not include any volumes or cash flows
+associated with the volumetric production payment.
+(b) Includes a reduction for estimated plugging and abandonment costs
+that is reflected as a liability on our balance sheet at December
+31, 2003, in accordance with Statement of Financial Accounting
+Standards No. 143.
+Our independent reserve engineers, Huddleston & Co., Inc., prepared the
+estimates of the proved reserves and the future net cash flows and present value
+thereof attributable to such proved reserves. Reserves were estimated using oil
+and gas prices and production and development costs in effect on December 31 of
+each such year, without escalation, and were otherwise prepared in accordance
+with Securities and Exchange Commission regulations regarding disclosure of oil
+and gas reserve information.
+There are numerous uncertainties inherent in estimating quantities of proved
+reserves, including many factors beyond our control or the control of the
+reserve engineers. Reserve engineering is a subjective
+22
+process of estimating underground accumulations of oil and gas that cannot be
+measured in an exact manner. The accuracy of any reserve or cash flow estimate
+is a function of the quality of available data and of engineering and geological
+interpretation and judgment. Estimates by different engineers often vary,
+sometimes significantly. In addition, physical factors, such as the results of
+drilling, testing and production subsequent to the date of an estimate, as well
+as economic factors, such as an increase or decrease in product prices that
+renders production of such reserves more or less economic, may justify revision
+of such estimates. Accordingly, reserve estimates could be different from the
+quantities of oil and gas that are ultimately recovered.
+We have not filed any reports with other federal agencies which contain an
+estimate of total proved net oil and gas reserves during our last fiscal year.
+PRESENT ACTIVITIES AND PRODUCTIVE WELLS
+The following table sets forth the wells we have drilled and completed during
+the periods indicated. All such wells were drilled in the continental United
+States primarily in federal and state waters in the Gulf of Mexico.
+YEARS ENDED DECEMBER 31,
+---------------------------------------------
+2003 2002 2001
+------------- ------------- -------------
+GROSS NET GROSS NET GROSS NET
+----- ----- ----- ----- ----- -----
+Development:
+Oil 2 .23 2 .30 6 .45
+Gas -- -- -- -- 4 3.17
+Non-productive -- -- 1 .40 -- --
+----- ----- ----- ----- ----- -----
+Total 2 .23 3 .70 10 3.62
+===== ===== ===== ===== ===== =====
+Exploration:
+Oil 1 .15 -- -- -- --
+Gas -- -- 1 .22 3 2.00
+Non-productive 1 .20 1 .50 12 5.77
+----- ----- ----- ----- ----- -----
+Total 2 .35 2 .72 15 7.77
+===== ===== ===== ===== ===== =====
+The following table sets forth our productive wells as of December 31, 2003:
+WELLS
+--------------
+GROSS NET
+------ -----
+Oil:
+Working interest 39.00 3.05
+Royalty interest 188.00 3.20
+------ ----
+Total 227.00 6.25
+====== ====
+Gas:
+Working interest 41.00 21.11
+Royalty interest 209.00 1.67
+------ ----
+Total 250.00 22.78
+====== =====
+23
+A well is categorized as an oil well or a natural gas well based upon the ratio
+of oil to gas reserves on a Mcfe basis. However, some of our wells produce both
+oil and gas. At December 31, 2003, we had no wells with multiple completions. At
+December 31, 2003, we had 1 gross (0.03 net) exploratory oil well in progress.
+LEASEHOLD ACREAGE
+The following table shows our approximate developed and undeveloped (gross and
+net) leasehold acreage as of December 31, 2003.
+LEASEHOLD ACREAGE
+-----------------------------------
+DEVELOPED UNDEVELOPED
+---------------- ----------------
+LOCATION GROSS NET GROSS NET
+-------------- ------- ------ ------- ------
+Louisiana 6,554 4,179 3,770 1,179
+Other states 680 362 681 509
+Federal waters 101,743 73,483 295,180 77,207
+------- ------ ------- ------
+Total 108,977 78,024 299,631 78,895
+======= ====== ======= ======
+As of December 31, 2003, we owned various royalty and overriding royalty
+interests in 1,336 net developed and 6,862 net undeveloped acres. In addition,
+we owned 4,711 developed and 121,289 undeveloped mineral acres.
+MAJOR CUSTOMERS
+Our production is sold generally on month-to-month contracts at prevailing
+prices. The following table identifies customers to whom we sold a significant
+percentage of our total oil and gas production during each of the 12-month
+periods ended:
+DECEMBER 31,
+----------------------
+2003 2002 2001
+---- ---- ----
+Petrocom Energy Group, Ltd. 4% 4% --
+Dynegy 5% 7% 8%
+Prior Energy Corporation 20% -- 20%
+Reliant Energy Services 28% 70% 49%
+Louis Dreyfus Energy Services 27% -- --
+Because alternative purchasers of oil and gas are readily available, we believe
+that the loss of any of these purchasers would not result in a material adverse
+effect on our ability to market future oil and gas production.
+TITLE TO PROPERTIES
+We believe that the title to our oil and gas properties is good and defensible
+in accordance with standards generally accepted in the oil and gas industry,
+subject to such exceptions which, in our opinion, are not so
+24
+material as to detract substantially from the use or value of such properties.
+Our properties are typically subject, in one degree or another, to one or more
+of the following:
+- royalties and other burdens and obligations, express or implied,
+under oil and gas leases;
+- overriding royalties and other burdens created by us or our
+predecessors in title;
+- a variety of contractual obligations (including, in some cases,
+development obligations) arising under operating agreements, farmout
+agreements, production sales contracts and other agreements that may
+affect the properties or their titles;
+- back-ins and reversionary interests existing under purchase
+agreements and leasehold assignments;
+- liens that arise in the normal course of operations, such as those
+for unpaid taxes, statutory liens securing obligations to unpaid
+suppliers and contractors and contractual liens under operating
+agreements;
+- pooling, unitization and communitization agreements, declarations
+and orders; and easements, restrictions, rights-of-way and other
+matters that commonly affect property.
+To the extent that such burdens and obligations affect our rights to production
+revenues, they have been taken into account in calculating our net revenue
+interests and in estimating the size and value of our reserves. We believe that
+the burdens and obligations affecting our properties are conventional in the
+industry for properties of the kind owned by us.
+ITEM 3. LEGAL PROCEEDINGS
+We are a defendant in various legal proceedings and claims, which arise in the
+ordinary course of our business. We do not believe the ultimate resolution of
+any such actions will have a material affect on our financial position or
+results of operations.
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
+There were no matters submitted to a vote of security holders during the fourth
+quarter of 2003.
+25
+PART II.
+ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
+Our common stock trades on the New York Stock Exchange under the symbol "CPE".
+The following table sets forth the high and low sale prices per share as
+reported for the periods indicated.
+QUARTER ENDED HIGH LOW
+-------------- ------ ------
+2002:
+First quarter $ 9.40 $ 3.97
+Second quarter 8.39 4.50
+Third quarter 5.15 3.20
+Fourth quarter 6.25 3.35
+2003:
+First quarter $ 4.35 $ 3.35
+Second quarter 8.44 3.66
+Third quarter 7.95 5.46
+Fourth quarter 11.48 7.31
+As of March 4, 2004, there were approximately 4,514 common stockholders of
+record.
+We have never paid dividends on our common stock and intend to retain our cash
+flow from operations, net of preferred stock dividends, for the future operation
+and development of our business. In addition, our primary credit facility and
+the terms of our outstanding subordinated debt prohibit the payment of cash
+dividends on our common stock.
+In December 2003, we borrowed $185 million pursuant to an amended and restated
+senior unsecured credit agreement dated December 23, 2003. In connection with
+our borrowings under the senior unsecured credit agreement, we issued to the
+lenders under the credit agreement warrants to purchase an aggregate of
+2,775,000 shares of our common stock at an exercise price of $10.00 per share.
+The warrants are exercisable for seven years from the date of issuance. The
+issuance of the warrants was exempt pursuant to Section 4(2) of the Securities
+Act of 1933.
+ITEM 6. SELECTED FINANCIAL DATA
+The following table sets forth, as of the dates and for the periods indicated,
+selected financial information about us. The financial information for each of
+the five years in the period ended December 31, 2003 has been derived from our
+audited Consolidated Financial Statements for such periods. The information
+should be read in conjunction with "Management's Discussion and Analysis of
+Financial Condition and Results of Operations" and the Consolidated Financial
+Statements and Notes thereto. The following information is not necessarily
+indicative of our future results.
+26
+CALLON PETROLEUM COMPANY
+SELECTED HISTORICAL FINANCIAL INFORMATION
+(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
+YEARS ENDED DECEMBER 31,
+--------------------------------------------------------------
+2003 2002 2001 2000 1999
+---------- ---------- ---------- ---------- ----------
+STATEMENT OF OPERATIONS DATA:
+Operating revenues:
+Oil and gas sales $ 73,697 $ 61,171 $ 60,010 $ 56,310 $ 37,140
+---------- ---------- ---------- ---------- ----------
+Operating expenses:
+Lease operating expenses 11,301 11,030 11,252 9,339 7,536
+Depreciation, depletion and amortization 28,253 27,096 21,081 17,153 16,727
+General and administrative 4,713 4,705 4,635 4,155 4,575
+Accretion expense 2,884 -- -- -- --
+Loss on mark-to-market commodity derivative contracts 535 708 -- -- --
+---------- ---------- ---------- ---------- ----------
+Total operating expenses 47,686 43,539 36,968 30,647 28,838
+---------- ---------- ---------- ---------- ----------
+Income (loss) from operations 26,011 17,632 23,042 25,663 8,302
+---------- ---------- ---------- ---------- ----------
+Other (income) expenses:
+Interest expense 30,614 26,140 12,805 8,420 6,175
+Other income (444) (1,004) (1,742) (1,767) (1,853)
+Loss on early extinguishment of debt 5,573 -- -- --
+Gain on sale of pipeline -- (2,454) -- -- --
+Gain on sale of Enron derivatives -- (2,479) -- -- --
+Writedown of Enron derivatives -- -- 9,186 -- --
+---------- ---------- ---------- ---------- ----------
+Total other (income) expenses 35,743 20,203 20,249 6,653 4,322
+---------- ---------- ---------- ---------- ----------
+Net income (loss) before income taxes (9,732) (2,571) 2,793 19,010 3,980
+Income tax expense (benefit) 8,432 (900) 977 6,463 1,353
+---------- ---------- ---------- ---------- ----------
+Net income (loss) before Medusa Spar LLC and
+cumulative effect of change in accounting principle (18,164) (1,671) 1,816 12,547 2,627
+Loss on Medusa Spar LLC, net of tax (8) -- -- -- --
+---------- ---------- ---------- ---------- ----------
+Net income (loss) before cumulative effect of change in
+in accounting principle (18,172) (1,671) 1,816 12,547 2,627
+Cumulative effect of change in accounting principle,
+net of tax 181 -- -- -- --
+---------- ---------- ---------- ---------- ----------
+Net income (loss) (17,991) (1,671) 1,816 12,547 2,627
+Preferred stock dividends 1,277 1,277 1,277 2,403 2,497
+---------- ---------- ---------- ---------- ----------
+Net income (loss) available to common shares $ (19,268) $ (2,948) $ 539 $ 10,144 $ 130
+========== ========== ========== ========== ==========
+27
+CALLON PETROLEUM COMPANY
+SELECTED HISTORICAL FINANCIAL INFORMATION
+(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
+YEARS ENDED DECEMBER 31,
+----------------------------------------------------
+2003 2002 2001 2000 1999
+-------- -------- -------- -------- --------
+Net income (loss) available to common shares $(19,268) $ (2,948) $ 539 $ 10,144 $ 130
+======== ======== ======== ======== ========
+Net income (loss) per common share:
+Basic:
+Net income (loss) available to common before cumulative
+effect of change in accounting principle $ (1.42) $ (.22) $ .04 $ .82 $ .01
+Cumulative effect of change in accounting principle,
+net of tax .01 -- -- -- --
+-------- -------- -------- -------- --------
+Net income (loss) available to common $ (1.41) $ (.22) $ .04 $ .82 $ .01
+======== ======== ======== ======== ========
+Diluted:
+Net income (loss) available to common before cumulative
+effect of change in accounting principle $ (1.42) $ (.22) $ .04 $ .80 $ .01
+Cumulative effect of change in accounting principle,
+net of tax .01 -- -- -- --
+-------- -------- -------- -------- --------
+Net income (loss) available to common $ (1.41) $ (.22) $ .04 $ .80 $ .01
+======== ======== ======== ======== ========
+Shares used in computing net income (loss) per common share:
+Basic 13,662 13,387 13,273 12,420 8,976
+======== ======== ======== ======== ========
+Diluted 13,662 13,387 13,366 12,745 9,075
+======== ======== ======== ======== ========
+BALANCE SHEET DATA (END OF PERIOD):
+Oil and gas properties, net $390,163 $377,661 $343,158 $258,613 $194,365
+Total assets $496,032 $410,613 $372,095 $301,569 $259,877
+Long-term debt, less current portion $214,885 $248,269 $161,733 $134,000 $100,250
+Stockholders' equity $133,261 $140,960 $147,224 $136,328 $124,380
+----------
+We use the full-cost method of accounting. Under this method of
+accounting, our net capitalized costs to acquire, explore and develop oil
+and gas properties may not exceed the standardized measure of our proved
+reserves. If these capitalized costs exceed a ceiling amount, the excess
+is charged to expense.
+28
+ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
+OF OPERATIONS
+The following discussion is intended to assist in an understanding of our
+financial condition and results of operations. Our Consolidated Financial
+Statements and Notes thereto contain detailed information that should be
+referred to in conjunction with the following discussion. See Item 8. "Financial
+Statements and Supplementary Data."
+GENERAL
+We have been engaged in the exploration, development, acquisition and production
+of oil and gas properties since 1950. Our revenues, profitability and future
+growth and the carrying value of our oil and gas properties are substantially
+dependent on prevailing prices of oil and gas and our ability to find, develop
+and acquire additional oil and gas reserves that are economically recoverable.
+Our ability to maintain or increase our borrowing capacity and to obtain
+additional capital on attractive terms is also influenced by oil and gas prices.
+Significant events of our financial and operating results for the year ended
+December 31, 2003 included:
+- borrowing $185 million for a term of seven-years at an interest rate
+of 9.75% pursuant to a senior unsecured credit agreement;
+- the contribution of our 15% working interest in the Medusa spar
+production facilities into a limited liability company in return for
+approximately $25 million of cash and a 10% interest in the limited
+liability company which will earn a throughput fee for production
+processed in the Medusa area; and
+- the commencement of production from two of our deepwater
+discoveries, Medusa and Habanero, in late November 2003 which is
+expected to increase production for 2004 by approximately 80% over
+2003 levels.
+- a charge of $11.5 million to income tax expense as the result of
+establishing a valuation allowance against our deferred tax asset
+required by SFAS 109 "Accounting for Income Taxes". This charge was
+taken due to the negative evidence resulting from the cumulative
+losses incurred for the three year period ending December 31, 2003.
+Relevant accounting guidance suggests that positive future
+expectations about income are diminished by such losses. If the
+Company achieves profitable operations in 2004, the Company expects
+it will reverse a portion of the valuation allowance in an amount at
+least sufficient to eliminate any tax provision in that period. See
+Note 3 to the Company's Consolidated Financial Statements for a more
+detailed discussion.
+These financial transactions allowed us to redeem $62.9 million of senior
+subordinated notes which were maturing in 2004, redeem $85.0 million of 12%
+loans maturing in March 2005 and reduce the outstanding balance under our senior
+secured credit facility. As a result, we expect that planned 2004 capital
+expenditures of approximately $65 million will be funded with cash flows from
+operations and draws under our senior secured credit facility, if necessary. The
+current borrowing base of $45 million under the senior secured credit facility,
+which had $30.0 million outstanding against it on December 31, 2003, is
+currently under review and may be increased since a majority of our reserves for
+Medusa and Habanero are now classified as proved developed reserves. This credit
+facility matures on June 30, 2004 and we
+29
+anticipate extending the due date or replacing it with a facility with similar
+or more favorable terms. For a more detailed discussion of outstanding debt see
+Note 5 to our Consolidated Financial Statements.
+Our estimated net proved oil and gas reserves decreased at December 31, 2003 to
+217 billion cubic feet of natural gas equivalent (Bcfe). This represents a
+decrease of 8% from previous year-end 2002 estimated proved reserves of 236
+Bcfe.
+We incurred a major downward revision to proved reserves in 2002 at our
+Boomslang discovery. The initial exploratory well drilled at this location in
+1998 encountered 185 feet of pay. The well was drilled with mechanical problems
+and was subsequently determined not to be a viable well for completion and
+production of the estimated proved reserves encountered in this initial well. A
+second well, drilled in the fourth quarter of 2002, to serve as a production
+take point, was drilled in a down dip direction from the first well targeting
+what was anticipated to be a better sand development in the three separate
+reservoirs found in the first well, but still up dip of the lowest known
+hydrocarbons in the first well. Reservoir sand quality changed dramatically,
+reducing the estimated reservoir volumes found and booked as estimated proved
+reserves by the first well to an extent that the partners determined that the
+risk of development was not economic. Callon had a 40% working interest. The
+Company's proved reserves in the prior year included 7.2 million barrels of oil
+and 13 billion cubic feet of natural gas attributable to Boomslang.
+Prices for oil and gas are subject to large fluctuations in response to
+relatively minor changes in the supply of and demand for oil and gas, market
+uncertainty and a variety of additional factors beyond our control. These
+factors include weather conditions in the United States, the condition of the
+United States economy, the actions of the Organization of Petroleum Exporting
+Countries, governmental regulation, political stability in the Middle East and
+elsewhere, the foreign supply of crude oil and natural gas, the price of foreign
+imports and the availability of alternate fuel sources. Any substantial and
+extended decline in the price of crude oil or natural gas would have an adverse
+effect on our carrying value of our proved reserves, borrowing capacity,
+revenues, profitability and cash flows from operations. We use derivative
+financial instruments (see Note 6 and Item 7A. "Quantitative and Qualitative
+Disclosures About Market Risks") for price protection purposes on a limited
+amount of our future production and do not use them for trading purposes. On a
+Mcfe basis, natural gas represents 45% of the budgeted 2004 production and 34%
+of proved reserves at year-end 2003.
+Inflation has not had a material impact on us and is not expected to have a
+material impact on us in the future.
+SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
+RECENT ACCOUNTING PRONOUNCEMENTS. In June 1998, the Financial Accounting
+Standards Board ("FASB") issued Statement of Financial Accounting Standards No.
+133 ("SFAS 133"), Accounting for Derivative Instruments and Hedging Activities.
+The Statement establishes accounting and reporting standards requiring that
+every derivative instrument, including certain derivative instruments embedded
+in other contracts, be recorded in the balance sheet as either an asset or
+liability measured at its fair value. SFAS 133 requires us to report changes in
+the fair value of our derivative financial instruments that qualify as cash flow
+hedges in other comprehensive income, a component of stockholders' equity, until
+realized. We adopted SFAS 133 effective January 1, 2001.
+In June 2001, the FASB issued Statement of Financial Accounting Standards No.
+143, Accounting for Asset Retirement Obligations ("SFAS 143") effective for
+fiscal years beginning after June 15, 2002. SFAS 143 essentially requires
+entities to record the fair value of a liability for obligations associated with
+the retirement of tangible long-lived assets and the associated asset retirement
+costs. We adopted the
+30
+statement on January 1, 2003 resulting in a cumulative effect of accounting
+change of $181,000, net of tax. See Note 8 to our Consolidated Financial
+Statements.
+In December 2002, the FASB issued Statement of Financial Accounting Standards
+No. 148 ("SFAS 148"), "Accounting for Stock-Based Compensation-Transition and
+Disclosure -an amendment of SFAS No. 123." SFAS 148 amends SFAS 123 to provide
+alternative methods of transition for a voluntary change to the fair value based
+method of accounting for stock-based employee compensation. In addition, this
+statement amends the disclosure requirements of SFAS 123 to require disclosures
+in both annual and interim financial statements about the method of accounting
+for stock-based employee compensation and the effect of the method used on the
+reported results. SFAS 148 is effective for the year ended December 31, 2002 and
+for interim financial statements commencing in 2003. The adoption of this
+pronouncement by us did not have an impact on our financial condition or results
+of operations.
+In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
+Variable Interest Entities, an Interpretation of Accounting Research Bulletin
+(ARB) 51" ("FIN 46"). FIN 46 addresses consolidation by business enterprises of
+variable interest entities ("VIEs"). The primary objective of FIN 46 is to
+provide guidance on the identification of, and financial reporting for, entities
+over which control is achieved through means other than voting rights; such
+entities are known as VIEs. The provisions of FIN 46 are effective immediately
+for these variable interest entities created after January 31, 2003. On December
+24, 2003, the FASB issued a revision to FIN 46 which among other things deferred
+the effective date for certain variable interests created prior to January 31,
+2003. Application is required for interests in special-purpose entities in the
+periods ending after December 15, 2003 and application is required for all other
+types of variable interest entities in the periods ending after March 31, 2004.
+We adopted FIN 46, as revised, as of December 31, 2003, which had no impact on
+the financial statements.
+In June 2001, the FASB issued Statement of Financial Accounting Standards No.
+141 ("SFAS 141"), "Business Combinations," which requires the use of the
+purchase method of accounting for business combinations initiated after June 30,
+2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also
+issued Statement of Financial Accounting Standards No. 142 ("SFAS 142"),
+"Goodwill and Other Intangible Assets," which discontinues the practice of
+amortizing goodwill and indefinite lived intangible assets and initiates an
+annual review of impairment. The new standard also requires that all intangible
+assets be aggregated and presented as a separate line item in the balance sheet.
+The adoption of SFAS No. 141 and 142 had no impact on the Company's financial
+position or results of operations. A reporting issue has arisen regarding the
+application of certain provisions of SFAS No. 141 and 142 to companies in the
+oil and gas industry. The issue is whether SFAS No. 141 requires registrants to
+classify the costs of mineral rights associated with extracting oil and gas as
+intangible assets in the balance sheet, apart from other capitalized oil and gas
+property costs, and provide specific footnote disclosures. Historically, the
+Company has included the costs of mineral rights associated with extracting oil
+and gas as a component of oil and gas properties. These costs include those to
+acquire contract based drilling and mineral use rights such as delay rentals,
+lease bonuses, commissions and brokerage fees, and other leasehold costs.
+The Emerging Issues Task Force ("EITF") has added the treatment of oil and gas
+mineral rights to an upcoming agenda, which may result in a change in the
+classification of these amounts, as described above. The Company will continue
+to classify its oil and gas leasehold costs as tangible oil and gas properties
+until further guidance is provided. The Company's cash flows and results of
+operations would not be affected since such intangible assets would continue to
+be depleted and assessed for impairment in accordance with full cost accounting
+rules, as allowed by SFAS No. 142. Further, the Company believes
+31
+that the amounts that would be classified as intangible assets as of December
+31, 2003 and 2002, would be immaterial.
+PROPERTY AND EQUIPMENT. We follow the full-cost method of accounting for oil and
+gas properties whereby all costs incurred in connection with the acquisition,
+exploration and development of oil and gas reserves, including certain overhead
+costs, are capitalized into the "full-cost pool." The amounts we capitalize into
+the full-cost pool are depleted (charged against earnings) using the
+unit-of-production method. The full-cost method of accounting for our proved oil
+and gas properties requires that we make estimates based on assumptions as to
+future events which could change. These estimates are described below.
+Depreciation, Depletion and Amortization (DD&A) of Oil and Gas Properties. We
+calculate depletion by using the capitalized costs in our full-cost pool plus
+future development and abandonment costs (combined, the depletable base) and our
+estimated net proved reserve quantities. Capitalized costs added to the
+full-cost pool and other costs added to the depletable base include the
+following:
+- the cost of drilling and equipping productive wells, dry hole costs,
+acquisition costs of properties with proved reserves, delay rentals
+and other costs related to exploration and development of our oil
+and gas properties;
+- our payroll and general and administrative costs and costs related
+to fringe benefits paid to employees directly engaged in the
+acquisition, exploration and/or development of oil and gas
+properties as well as other directly identifiable general and
+administrative costs associated with such activities. Such
+capitalized costs do not include any costs related to our production
+of oil and gas or our general corporate overhead;
+- costs associated with properties that do not have proved reserves
+attributed to them are excluded from the full cost pool. These
+unevaluated property costs are added to the full cost pool at such
+time as wells are completed on the properties, the properties are
+sold or we determine these costs have been impaired. Our
+determination that a property has or has not been impaired (which is
+discussed below) requires that we make assumptions about future
+events;
+- our estimates of future costs to develop proved properties are added
+to the full cost pool for purposes of the DD&A computation. We use
+assumptions based on the latest geologic, engineering, regulatory
+and cost data available to us to estimate these amounts. However,
+the estimates we make are subjective and may change over time. Our
+estimates of future development costs are periodically updated as
+additional information becomes available; and
+- prior to the adoption of SFAS 143, estimated costs to dismantle,
+abandon and restore a proved property were added to the full cost
+pool for the purposes of DD&A. Subsequent to the adoption of SFAS
+143, effective January 1, 2003, these costs are included in the full
+cost pool. Such cost estimates are periodically updated as
+additional information becomes available. As discussed above under
+Accounting Pronouncements, specifically SFAS 143, beginning January
+1, 2003, we changed the method for which we account for such costs.
+Capitalized costs included in the full-cost pool are depleted and charged
+against earnings using the unit of production method. Under this method, we
+estimate our quantity of proved reserves at the beginning of each accounting
+period. For each barrel of oil equivalent produced during the period, we record
+a depletion charge equal to the amount included in the depletable base (net of
+accumulated depreciation, depletion and amortization) divided by our estimated
+net proved reserve quantities.
+Because we use estimates and assumptions to calculate proved reserves (as
+discussed below) and the amounts included in the full-cost pool, our depletion
+calculations will change if the estimates and assumptions are not realized. Such
+changes may be material.
+32
+Ceiling Test. Under the full-cost accounting rules, capitalized costs included
+in the full-cost pool, net of accumulated depreciation, depletion and
+amortization (DD&A), cost of unevaluated properties and deferred income taxes,
+may not exceed the present value of our estimated future net cash flows from
+proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or
+fair value of unproved properties included in the costs being amortized, net of
+related tax effects. These rules generally require that, in estimating future
+net cash flow, we assume that future oil and gas production will be sold at the
+unescalated market price for oil and gas received at the end of each fiscal
+quarter and that future costs to produce oil and gas will remain constant at the
+prices in effect at the end of the fiscal quarter. We are required to write-down
+and charge to earnings the amount, if any, by which these costs exceed the
+discounted future net cash flows, unless prices recover sufficiently before the
+date of our financial statements. Given the volatility of oil and gas prices, it
+is likely that our estimates of discounted future net cash flows from proved oil
+and gas reserves will change in the near term. If oil and gas prices decline
+significantly, even if only for a short period of time, it is possible that
+writedowns of oil and gas properties could occur in the future.
+Estimating Reserves and Present Values. Our estimates of quantities of proved
+oil and gas reserves and the discounted present value of such reserves at the
+end of each quarter are based on numerous assumptions which are likely to change
+over time. These assumptions include:
+- the prices at which we can sell our oil and gas production in the
+future. Oil and gas prices are volatile, but we are generally
+required to assume that they will not change from the prices in
+effect at the end of the quarter. In general, higher oil and gas
+prices will increase quantities of proved reserves and the present
+value of such reserves, while lower prices will decrease these
+amounts. Because our properties have relatively short productive
+lives, changes in prices will affect the present value more than
+quantities of oil and gas reserves; and
+- the costs to develop and produce our reserves and the costs to
+dismantle our production facilities when reserves are depleted.
+These costs are likely to change over time, but we are required to
+assume that costs in effect at the end of the quarter will not
+change. Increases in costs will reduce oil and gas quantities and
+present values, while decreases in costs will increase such amounts.
+Because our properties have relatively short productive lives,
+changes in costs will affect the present value more than quantities
+of oil and gas reserves.
+- the potential liability to pay royalties to the Mineral Management
+Service on some of the Company's properties which qualify for
+royalty relief under the Deep Water Royalty Relief Act could reduce
+proved reserves. See Note 7 of our Consolidated Financial Statements
+for a more detailed discussion of this potential liability.
+In addition, the process of estimating proved oil and gas reserves requires that
+our independent and internal reserve engineers exercise judgment based on
+available geological, geophysical and technical information. We have described
+the risks associated with reserve estimation and the volatility of oil and gas
+prices, under "Risk Factors" .
+Unproved Properties. Costs associated with properties that do not have proved
+reserves, including capitalized interest, are excluded from the full-cost pool.
+These unproved properties are included in the line item "Unevaluated properties
+excluded from amortization." Unproved property costs are transferred to the
+full-cost pool when wells are completed on the properties or the properties are
+sold. In addition, we are required to determine whether our unproved properties
+are impaired and, if so, add the costs of such properties to the full-cost pool.
+We determine whether an unproved property should be impaired by periodically
+reviewing our exploration program on a property by property basis. This
+determination may require the exercise of substantial judgment by our
+management.
+33
+DERIVATIVES. We use derivative financial instruments for price protection
+purposes on a limited amount of our future production and do not use them for
+trading purposes. Such derivatives were accounted for in years prior to 2001 as
+hedges and have been recognized as an adjustment to oil and gas sales in the
+period in which they are related. We currently use the accounting treatment for
+derivatives specified under SFAS 133.
+INCOME TAXES. We follow the asset and liability method of accounting for
+deferred income taxes prescribed by Statement of Financial Accounting Standards
+No. 109 ("SFAS 109") "Accounting for Income Taxes". The statement provides for
+the recognition of a deferred tax asset for deductible temporary timing
+differences, capital and operating loss carryforwards, statutory depletion
+carryforward and tax credit carryforwards, net of a "valuation allowance". The
+valuation allowance is provided for that portion of the asset, for which it is
+deemed more likely than not, that it will not be realized.
+SFAS 109 provides for the weighing of positive and negative evidence in
+determining whether it is more likely than not that a deferred tax asset is
+recoverable. We have incurred losses in 2002 and 2003 and have losses on an
+aggregate basis for the three-year period ended December 31, 2003. However, as
+discussed in Note 5, in December 2003 we refinanced nearly all our highest cost
+debt, incurring an early extinguishment loss of $5.6 million, but achieving
+significant interest savings in the future. In addition, as discussed in Note 5,
+the first two of our deepwater projects began production in November 2003, which
+is expected to result in a significant increase in 2004 production as compared
+to 2003. Nevertheless, relevant accounting guidance suggests that a recent
+history of cumulative losses constitutes significant negative evidence, and that
+future expectations about income are overshadowed by such recent losses. As a
+result, we established a valuation allowance of $11.5 million as of December 31,
+2003. If we achieve profitable operations in 2004, we expect to reverse a
+portion of the valuation allowance in an amount at least sufficient to eliminate
+any tax provision in that period. See Note 3 of our Consolidated Financial
+Statements for further disclosure.
+LIQUIDITY AND CAPITAL RESOURCES
+Our primary sources of capital are cash flows from operations, borrowings from
+financial institutions and the sale of debt and equity securities. Net cash and
+cash equivalents increased during 2003 to $8.7 million, up $2.9 million. Cash
+provided from operating activities during 2003 totaled $34.6 million, up from
+$12.2 million in 2002. Cash provided by operating activities during 2004 is
+expected to increase significantly due to the Medusa and Habanero deepwater
+projects commencing production in late November 2003. Dividends paid on
+preferred stock were $1.3 million. Most of our outstanding debt was restructured
+during December 2003. The restructuring of our debt is discussed in the
+following paragraphs.
+In December 2003 we borrowed $185 million pursuant to a senior unsecured credit
+facility with a stated interest rate of 9.75%. The net proceeds from the loans
+of $181.3 million were used to redeem $22.9 million of 10.125% senior
+subordinated notes due July 31, 2004, $40 million of 10.25% senior subordinated
+notes due September 15, 2004, $85 million of our 12% loans due March 31, 2005
+plus a 1% call premium of $850,000 and to reduce the balance outstanding under
+our senior secured revolving credit facility. A charge of $5.3 million was
+incurred in 2003 as a result of the early extinguishment of debt for the 12%
+loans due March 31, 2005 and a charge of approximately $1.4 million will be
+incurred in 2004 for the early extinguishment of the $22.9 million 10.125%
+senior subordinated notes due July 31, 2004 and the $40 million 10.25% senior
+subordinated notes due September 15, 2004. We exercised covenant defeasance
+under the indentures for the 10.125% and 10.25% notes on December 8, 2003 and
+distributed a required 30-
+34
+day redemption notice. The funds necessary to redeem the notes were placed in
+trust and the trustee paid the holders of the notes on January 8, 2004. The
+funds in trust were classified on our December 31, 2003 balance sheet as
+restricted cash. In conjunction with the new senior unsecured notes, we issued
+detachable warrants to purchase 2.775 million of our common stock at an exercise
+price of $10 per share. This senior unsecured debt matures December 8, 2010. See
+Note 5 of our Consolidated Financial Statements for a more detailed description
+of these securities.
+In December 2003, we announced the formation of a limited liability company,
+Medusa Spar LLC, which now owns a 75% undivided ownership interest in the
+deepwater spar production facilities on our Medusa Field in the Gulf of Mexico.
+We contributed a 15% undivided ownership interest in the production facility to
+the LLC in return for approximately $25 million in cash and a 10% ownership
+interest in the LLC. Our cash proceeds were used to reduce the balance
+outstanding under our senior secured credit facility. The LLC will earn a tariff
+based upon production volume throughput from the Medusa area. We are obligated
+to process our share of production from the Medusa field and any future
+discoveries in the area through the spar production facilities. The LLC used the
+cash proceeds from $83.7 of non-recourse financing and a cash contribution by
+one of the LLC owners to acquire its 75% interest in the spar. The balance of
+the LLC is owned by Oceaneering International, Inc. (NYSE:OII) and Murphy Oil
+Corporation (NYSE:MUR). We are accounting for our 10% ownership interest in the
+LLC under the equity method.
+Our remaining maturities for unsecured debt, excluding the $185 million in 9.75%
+loans due 2010, consists of $10 million of the 12% loans with a due date of
+March 31, 2005 and $33 million of 11% senior subordinated notes with a due date
+of December 15, 2005. These 2005 maturities will be retired by our primary
+sources of capital which are cash flows from operations, borrowings from
+financial institutions and the sale of debt and equity securities. See Note 5 of
+our Consolidated Financial Statements for a more detailed description of these
+securities
+Borrowings under our senior secured credit facility are secured by mortgages
+covering substantially all of our producing oil and gas properties. This
+facility had a $45 million borrowing base on December 31, 2003 with $30 million
+outstanding against it. As of February 29, 2004, $20 million in loans were
+outstanding under the facility. The borrowing base is currently being reviewed
+by the lenders and could be increased due to our proved producing reserves
+increasing as a result of the Medusa and Habanero fields commencing production
+late in the fourth quarter of 2003. The facility expires on June 30, 2004 and we
+are currently reviewing options to extend the maturity date or to replace the
+facility with one that is similar or with more favorable terms. See Note 5 of
+our Consolidated Financial Statements for a more detailed description of the
+credit facility.
+Outstanding debt on December 31, 2003 was $308.1 million, and after retirement
+of the 2004 notes using restricted cash on January 8, 2004, debt was $245.2
+million, compared to $249.6 million on December 31, 2002. The senior secured
+credit facility, our two senior unsecured credit facilities and the indenture
+for our senior subordinated debt contain various covenants including
+restrictions on additional indebtedness and payment of cash dividends as well as
+maintenance of certain financial ratios. We were in compliance with these
+covenants at December 31, 2003.
+Capital expenditure plans for 2004 include:
+- the completion of the development projects for Medusa and Habanero;
+- the drilling of a satellite prospect in the Medusa field;
+- the drilling and completion of a proved undeveloped location in the
+Mobile Blocks 952/953/955 field;
+- the acquisition of seismic and leases; and
+35
+- discretionary capital projects for the exploratory drilling of deep
+shelf prospects we developed through our 3-D seismic partnership
+using AVO technology.
+We anticipate that cash flow generated during 2004 and current availability
+under our senior secured credit facility, if necessary, will provide the $65
+million, which includes capitalized interest and general and administrative
+expenses, of capital necessary to fund these planned capital expenditures and
+the current portion of our asset retirement obligation in the amount of $8.6
+million.
+The following table describes our outstanding contractual obligations (in
+thousands) as of December 31, 2003:
+CONTRACTUAL LESS THAN ONE-THREE FOUR-FIVE AFTER-FIVE
+OBLIGATIONS TOTAL ONE YEAR YEARS YEARS YEARS
+----------- ------- --------- --------- --------- ----------
+Senior Secured Revolving Credit Facility $30,000 $30,000(b) $ -- $ -- $ --
+10.125% Senior Subordinated Notes 22,915 22,915(a) -- -- --
+10.25% Senior Subordinated Notes 40,000 40,000(a) -- -- --
+12% Senior Loans 10,000 -- 10,000 -- --
+9.75% Senior Unsecured Credit Facility 185,000 -- -- -- 185,000
+11% Senior Subordinated Notes 33,000 -- 33,000 -- --
+Capital lease (future minimum payments) 4,421 1,890 1,261 577 693
+Throughput Commitments:
+Medusa Spar 23,128 5,628 8,660 5,532 3,308
+Medusa Oil Pipeline 1,129 269 460 186 214
+(a) These notes were retired with restricted cash on January 8, 2004.
+(b) This facility matures June 30, 2004 and is expected to be extended or
+replaced with a new facility.
+36
+RESULTS OF OPERATIONS
+The following table sets forth certain operating information with respect to our
+oil and gas operations for each of the three years in the period ended December
+31, 2003.
+DECEMBER 31,
+---------------------------------
+2003(A) 2002(A)(B) 2001(A)(B)
+------- ---------- ----------
+Production:
+Oil (MBbls) 268 226 273
+Gas (MMcf) 12,315 14,215 13,566
+Total production (MMcfe) 13,923 15,571 15,206
+Average daily production (MMcfe) 38.1 42.7 41.7
+Average sales price:
+Oil (per Bbl) $ 28.72 $ 23.11 $ 22.95
+Gas (per Mcf) $ 5.36 $ 3.94 $ 3.96
+Total (per Mcfe) $ 5.29 $ 3.93 $ 3.95
+Oil and Gas revenues:
+Gas revenue $66,001 $55,949 $53,729
+Oil revenue 7,696 5,222 6,281
+------- ------- -------
+Total $73,697 $61,171 $60,010
+======= ======= =======
+Oil and gas production costs:
+Lease operating expenses $11,301 $11,030 $11,252
+Additional per Mcfe data:
+Sale price $ 5.29 $ 3.93 $ 3.95
+Lease operating expenses .81 .71 .73
+------- ------- -------
+Operating margin $ 4.48 $ 3.22 $ 3.22
+======= ======= =======
+Depletion $ 2.03 $ 1.73 $ 1.37
+Accretion $ .21 $ -- $ --
+General and administrative (net of management fees) $ .34 $ .30 $ .30
+(a) Average sales price includes hedging gains and losses.
+(b) Production volumes include 1,200 MMcf for the year 2002 and 2,300 MMcf for
+2001, at an average price of $2.08 per Mcf associated with a volumetric
+production payment.
+37
+OFF-BALANCE SHEET ARRANGEMENTS
+In December 2003, we announced the formation of a limited liability company,
+Medusa Spar LLC, which now owns a 75% undivided ownership interest in the
+deepwater spar production facilities on our Medusa Field in the Gulf of Mexico.
+We contributed a 15% undivided ownership interest in the production facility to
+Medusa Spar LLC in return for approximately $25 million in cash and a 10%
+ownership interest in the LLC. The LLC will earn a tariff based upon production
+volume throughput from the Medusa area. We are obligated to process our share of
+production from the Medusa field and any future discoveries in the area through
+the spar production facilities. This arrangement allows us to defer the cost of
+the Spar production facility over the life of the Medusa field. Our cash
+proceeds were used to reduce the balance outstanding under our senior secured
+credit facility. The LLC used the cash proceeds from $83.7 of non-recourse
+financing and a cash contribution by one of the LLC owners to acquire its 75%
+interest in the spar. The balance of Medusa Spar LLC is owned by Oceaneering
+International, Inc. (NYSE:OII) and Murphy Oil Corporation (NYSE:MUR). We are
+accounting for our 10% ownership interest in the LLC under the equity method.
+SEC INQUIRIES REGARDING RESERVE INFORMATION
+Beginning in October 2002 we received a series of inquiries from the SEC
+regarding our Annual Report on Form 10-K for the year ended December 31, 2001
+requesting supplemental information concerning our operations in the Gulf of
+Mexico. The comment letters requested information about the procedures we used
+to classify our deepwater reserves as proved and requested that our financials
+be restated to reflect the removal of the Boomslang reserves as proved for all
+prior periods during which such reserves were reported as proved. We have
+reviewed the SEC comments with our independent petroleum reserve engineers,
+Huddleston & Co., Inc., of Houston, Texas. Both Huddleston & Co. and we believe
+that such deepwater reserves are properly classified as proved. The Company has
+responded to all of the SEC inquiries.
+COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2003 AND
+2002
+OIL AND GAS REVENUES
+Total oil and gas revenues increased 20% from $61.2 million in 2002 to $73.7 in
+2003 while total production for 2003 decreased by 11% versus 2002. Realized oil
+and gas prices were substantially higher when compared to the same period in
+2002 and accounted for the increase in revenue. Gas revenues for 2002 included
+$9.2 million of non-cash revenue related to the Enron derivatives discussed in
+Note 6 to the Consolidated Financial Statements.
+Gas production during 2003 totaled 12.3 Bcf and generated $66.0 million in
+revenues compared to 14.2 Bcf and $55.9 million in revenues during the same
+period in 2002. Average gas prices for 2003 were $5.36 per Mcf compared to $3.94
+per Mcf during the same period last year. The decrease in production was
+primarily due to the depletion of the lowest productive zone of the East Cameron
+Block 294 field. The well at East Cameron Block 294 was returned to production
+after a recompletion to a behind pipe zone in the third quarter of 2003. Also,
+the sale of the North and Northwest Dauphin Island fields in the fourth quarter
+of 2002 and the normal and expected declines in production from other properties
+contributed to the variance.
+Oil production during 2003 totaled 268,000 barrels and generated $7.7 million in
+revenues compared to 226,000 barrels and $5.2 million in revenues for the same
+period in 2002. Average oil prices received in
+38
+2003 were $28.72 per barrel compared to $23.11 per barrel in 2002. The increase
+in production was due to the initial production from our deepwater discoveries,
+Medusa and Habanero, which began producing late in the fourth quarter of 2003.
+This was offset slightly by downtime for maintenance to the facility and
+equipment at the Big Escambia Creek Field operated by ExxonMobil Corporation and
+normal and expected declines in production from older properties.
+LEASE OPERATING EXPENSES
+Lease operating expenses for 2003 increased by 2% to $11.3 million compared to
+$11.0 million for the same period in 2002. The increase was primarily due to the
+increase in lease operating expenses for the Mobile Block 864 area resulting
+from the implementation of the accelerated production program in the second
+quarter of 2002 and lease operating expenses related to our deepwater
+discoveries, Medusa and Habanero, which began producing late in the fourth
+quarter of 2003. The increase was slightly offset as a result of the sale of
+North and Northwest Dauphin Island fields in the fourth quarter of 2002 which
+reduced lease operating expenses for 2003.
+DEPRECIATION, DEPLETION AND AMORTIZATION
+Depreciation, depletion and amortization for 2003 and 2002 were $28.3 million
+and $27.1 million, respectively. The 4% increase was due primarily to the
+downward reserve revisions for our Boomslang field at Ewing Bank Block 994 at
+the end of 2002. This decrease in estimated proved reserves increased the
+depletable cost per unit of production.
+ACCRETION EXPENSE
+Accretion expense of $2.9 million represents accretion for our asset retirement
+obligations for 2003.
+GENERAL AND ADMINISTRATIVE
+General and administrative expenses for 2003, net of amounts capitalized, were
+$4.7 million and flat with the amount incurred in 2002.
+INTEREST EXPENSE
+Interest expense increased by 17% in 2003 to $30.6 million compared to $26.1
+million in 2002. This was a result of higher debt levels.
+LOSS ON EARLY EXTINGUISHMENT OF DEBT
+A loss of $5.6 million was incurred in December of 2003 for the write-off of
+deferred financing costs and bond discounts associated with the early
+extinguishment of $85 million of the 12% loans due in 2005 plus a 1% pre-payment
+premium.
+INCOME TAXES
+The income tax expense of $8.4 million in 2003 was primarily due to a charge of
+$11.5 million to establish a valuation allowance against our deferred tax asset
+required by SFAS 109 "Accounting for Income Taxes". This charge was taken due to
+the negative evidence resulting from the cumulative losses incurred for the
+three year period ending December 31, 2003. Relevant accounting guidance
+suggests that positive future expectations about income are diminished by such
+losses. If the Company achieves
+39
+profitable operations in 2004, the Company expects it will reverse a portion of
+the valuation allowance in an amount at least sufficient to eliminate any tax
+provision in that period. See Note 3 to the Company's Consolidated Financial
+Statements for a more detailed discussion.
+COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2002 AND
+2001
+OIL AND GAS REVENUES
+Oil and gas revenues for 2002 were $61.2 million, a 2% increase from the 2001
+amount of $60.0 million. Oil and gas production of 15,571 MMcfe during 2002
+increased as well from the 2001 amount of 15,206 MMcfe.
+Oil production decreased from 273,000 barrels in 2001 to 226,000 barrels in 2002
+but the average sales price increased from $22.95 in 2001 to $23.11 in 2002. As
+a result, oil revenues dropped from $6.3 million in 2001 to $5.2 million in
+2002. The production decrease was primarily due to older properties' normal and
+expected decline in production.
+Gas revenues for 2002 were $55.9 million based on sales of 14.2 Bcf at an
+average sales price of $3.94 per Mcf. For 2001, gas revenues were $53.7 million
+based on production of 13.6 Bcf sold at an average sales price of $3.96 per Mcf.
+Our gas production in 2002 increased when compared to last year due primarily to
+the acceleration program at Mobile Blocks 952/953/955 area initiated in the
+fourth quarter of 2001.
+LEASE OPERATING EXPENSES
+Lease operating expenses remained relatively stable at $11.0 million ($.71 per
+Mcfe) in 2002 compared to $11.3 million ($.73 per Mcfe) in 2001.
+DEPRECIATION, DEPLETION AND AMORTIZATION
+Depreciation, depletion and amortization increased by 28% due in large part to
+the downward reserve revisions at Boomslang. This decrease in estimated proved
+reserves, over which depletable costs are amortized, increased the per unit
+depletion rate, while production remained relatively constant between years.
+Total charges increased from $21.1 million or $1.39 per Mcfe in 2001, to $27.1
+million, or $1.74 per Mcfe in 2002.
+GENERAL AND ADMINISTRATIVE
+General and administrative expenses for 2002 were $4.7 million, or $.30 per
+Mcfe, compared to $4.6 million, or $.30 per Mcfe, in 2001.
+INTEREST EXPENSE
+Interest expense for 2002 was $26.1 million increasing from $12.8 million in
+2001. This is a result of an increase in our long-term debt as well as higher
+interest rates associated with additional debt incurred in 2002.
+40
+INCOME TAXES
+Our 2002 results included a deferred income tax benefit of $900,000. We
+evaluated the deferred income tax asset in light of our reserve quantity
+estimates, our long-term outlook for oil and gas prices and our expected level
+of future revenues and expenses. We believe it is more likely than not, based
+upon this evaluation, that we will realize the recorded deferred income tax
+asset. However, there is no assurance that such asset will ultimately be
+realized.
+41
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
+The Company's revenues are derived from the sale of its crude oil and natural
+gas production. In recent months, the prices for oil and gas have increased;
+however, they remain extremely volatile and sometimes experience large
+fluctuations as a result of relatively small changes in supplies, weather
+conditions, economic conditions and government actions. The Company enters into
+derivative financial instruments to hedge oil and gas price risks for the
+production volumes to which the hedge relates. The derivatives reduce the
+Company's exposure on the hedged volumes to decreases in commodity prices and
+limit the benefit the Company might otherwise have received from any increases
+in commodity prices on the hedged volumes.
+The Company also enters into price "collars" to reduce the risk of changes in
+oil and gas prices. Under these arrangements, no payments are due by either
+party so long as the market price is above the floor price set in the collar and
+below the ceiling. If the price falls below the floor, the counter-party to the
+collar pays the difference to the Company and if the price is above the ceiling,
+the counter-party receives the difference from the Company. The Company enters
+into these various agreements to reduce the effects of volatile oil and gas
+prices and does not enter into hedge transactions for speculative purposes. See
+Note 6 to the Consolidated Financial Statements for a description of the
+Company's hedged position at December 31, 2003. There have been no significant
+changes in market risks faced by the Company since the end of 2003.
+Based on projected annual sales volumes for 2004 (excluding forecast production
+increases over 2003), a 10% decline in the prices we receive for our crude oil
+and natural gas production would have an approximate $13.7 million impact on our
+revenues.
+42
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
+Page
+---------
+Report of Independent Auditors 44 and 45
+Consolidated Balance Sheets as of December 31, 2003 46
+and 2002
+Consolidated Statements of Operations for Each of the Three Years
+in the Period Ended December 31, 2003 47
+Consolidated Statements of Stockholders' Equity
+for Each of the Three Years in the Period Ended December 31, 2003 48
+Consolidated Statements of Cash Flows for Each of the Three Years
+in the Period Ended December 31, 2003 49
+Notes to Consolidated Financial Statements 50
+43
+REPORT OF INDEPENDENT AUDITORS
+The Stockholders and Board of Directors
+Callon Petroleum Company
+We have audited the accompanying consolidated balance sheets of Callon
+Petroleum Company as of December 31, 2003 and 2002, and the related consolidated
+statements of operations, stockholders' equity and cash flows for the two years
+in the period ended December 31, 2003. These financial statements are the
+responsibility of the Company's management. Our responsibility is to express an
+opinion on these financial statements based on our audits. The financial
+statements of Callon Petroleum Company as of December 31, 2001 and for the year
+then ended, were audited by other auditors who have ceased operations and whose
+report dated March 29, 2002, expressed an unqualified opinion on those
+statements and included an explanatory paragraph that disclosed the change in
+the Company's method of accounting for derivative instruments and hedging
+activities discussed in Note 2 to those financial statements.
+We conducted our audits in accordance with auditing standards generally
+accepted in the United States. Those standards require that we plan and perform
+the audit to obtain reasonable assurance about whether the financial statements
+are free of material misstatement. An audit includes examining, on a test basis,
+evidence supporting the amounts and disclosures in the financial statements. An
+audit also includes assessing the accounting principles used and significant
+estimates made by management, as well as evaluating the overall financial
+statement presentation. We believe that our audits provide a reasonable basis
+for our opinion.
+In our opinion, the financial statements referred to above present fairly,
+in all material respects, the consolidated financial position of Callon
+Petroleum Company as of December 31, 2003 and 2002, and the results of its
+operations and its cash flows for the two years in the period ended December 31,
+2003, in conformity with accounting principles generally accepted in the United
+States.
+As discussed in Note 1 to the financial statements, effective January 1,
+2003, the Company adopted Statement of Financial Accounting Standards No. 143,
+"Accounting for Asset Retirement Obligations".
+ERNST & YOUNG LLP
+New Orleans, Louisiana
+March 3, 2004
+44
+The following report is a copy of the audit report previously issued by Arthur
+Andersen LLP in connection with Callon Petroleum Company's annual report on Form
+10-K for the year ended December 31, 2001. This audit report has not been
+reissued by Arthur Andersen LLP in connection with this filing on form 10-K for
+the year ended December 31, 2003. The consolidated balance sheet as of December
+31, 2000 and the consolidated statements of operations, stockholders' equity and
+cash flows for the year ended December 31, 2000, mentioned in the report, are
+not required in the Company's annual report for 2003 and are therefore not
+presented among the financial statements in this annual report.
+REPORT OF INDEPENDENT AUDITORS
+To the Stockholders and Board of Directors of Callon Petroleum Company:
+We have audited the accompanying consolidated balance sheets of Callon
+Petroleum Company (a Delaware corporation) and subsidiaries as of December 31,
+2001 and 2000, and the related consolidated statements of operations,
+stockholders' equity and cash flows for each of the three years in the period
+ended December 31, 2001. These financial statements are the responsibility of
+the Company's management. Our responsibility is to express an opinion on these
+financial statements based on our audits.
+We conducted our audits in accordance with auditing standards generally
+accepted in the United States. Those standards require that we plan and perform
+the audit to obtain reasonable assurance about whether the financial statements
+are free of material misstatement. An audit includes examining, on a test basis,
+evidence supporting the amounts and disclosures in the financial statements. An
+audit also includes assessing the accounting principles used and significant
+estimates made by management, as well as evaluating the overall financial
+statement presentation. We believe that our audits provide a reasonable basis
+for our opinion.
+In our opinion, the financial statements referred to above present fairly,
+in all material respects, the financial position of Callon Petroleum Company and
+subsidiaries, as of December 31, 2001 and 2000, and the results of their
+operations and their cash flows for each of the three years in the period ended
+December 31, 2001, in conformity with accounting principles generally accepted
+in the United States.
+As discussed in Note 2 to the consolidated financial statements effective
+January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivative
+Instruments and Hedging Activities."
+ARTHUR ANDERSEN LLP
+New Orleans, Louisiana
+MARCH 29, 2002
+45
+CALLON PETROLEUM COMPANY
+CONSOLIDATED BALANCE SHEETS
+(IN THOUSANDS, EXCEPT SHARE DATA)
+DECEMBER 31,
+---------------------
+2003 2002
+--------- ---------
+ASSETS
+Current assets:
+Cash and cash equivalents $ 8,700 $ 5,807
+Restricted cash 63,345 --
+Accounts receivable 10,117 10,875
+Other current assets 3,606 570
+--------- ---------
+Total current assets 85,768 17,252
+--------- ---------
+Oil and gas properties, full-cost accounting method:
+Evaluated properties 802,912 762,918
+Less accumulated depreciation, depletion and amortization (447,000) (426,254)
+--------- ---------
+355,912 336,664
+Unevaluated properties excluded from amortization 34,251 40,997
+--------- ---------
+Total oil and gas properties 390,163 377,661
+--------- ---------
+Pipeline and other facilities, net -- 853
+Other property and equipment, net 1,547 1,890
+Deferred tax asset -- 8,767
+Long-term gas balancing receivable 1,101 761
+Restricted investments 7,420 --
+Investment in Medusa Spar LLC 8,471 --
+Other assets, net 1,562 3,429
+--------- ---------
+Total assets $ 496,032 $ 410,613
+========= =========
+LIABILITIES AND STOCKHOLDERS' EQUITY
+Current liabilities:
+Accounts payable and accrued liabilities $ 16,020 $ 12,498
+Undistributed oil and gas revenues 897 1,109
+Accrued net profits interest payable 1,886 1,707
+Asset retirement obligations, current portion 8,571 --
+Current maturities of long-term debt 93,223 1,320
+--------- ---------
+Total current liabilities 120,597 16,634
+--------- ---------
+Long-term debt-excluding current maturities 214,885 248,269
+Accounts payable and accrued liabilities to be refinanced -- 3,861
+Asset retirement obligations 25,120 --
+Accrued retirement benefits 189 204
+Other long-term liabilities 1,980 685
+--------- ---------
+Total liabilities 362,771 269,653
+--------- ---------
+Stockholders' equity:
+Preferred Stock, $.01 par value; 2,500,000 shares
+authorized; 600,861 shares of Convertible
+Exchangeable Preferred Stock, Series A issued
+and outstanding at December 31, 2003
+with a liquidation preference of $15,021,525 6 6
+Common Stock, $.01 par value; 20,000,000 shares
+authorized; 13,935,311 shares and 13,900,466 shares
+outstanding at December 31, 2003 and 2002, respectively 139 139
+Capital in excess of par value 169,036 158,370
+Unearned restricted stock compensation (372) (826)
+Accumulated other comprehensive income (loss) (20) (469)
+Retained earnings (deficit) (35,528) (16,260)
+--------- ---------
+Total stockholders' equity 133,261 140,960
+--------- ---------
+Total liabilities and stockholders' equity $ 496,032 $ 410,613
+========= =========
+The accompanying notes are an integral part of these financial statements.
+46
+CALLON PETROLEUM COMPANY
+CONSOLIDATED STATEMENTS OF OPERATIONS
+FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
+(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
+2003 2002 2001
+-------- -------- --------
+Operating revenues:
+Oil and gas sales $ 73,697 $ 61,171 $ 60,010
+-------- -------- --------
+Operating expenses:
+Lease operating expenses 11,301 11,030 11,252
+Depreciation, depletion and amortization 28,253 27,096 21,081
+General and administrative 4,713 4,705 4,635
+Accretion expense 2,884 -- --
+Loss on mark-to-market commodity derivative contracts 535 708 --
+-------- -------- --------
+Total operating expenses 47,686 43,539 36,968
+-------- -------- --------
+Income from operations 26,011 17,632 23,042
+-------- -------- --------
+Other (income) expenses:
+Interest expense 30,614 26,140 12,805
+Other income (444) (1,004) (1,742)
+Loss on early extinguishment of debt 5,573 -- --
+Gain on sale of pipeline -- (2,454) --
+Gain on sale of Enron derivatives -- (2,479) --
+Writedown of Enron derivatives -- -- 9,186
+-------- -------- --------
+Total other (income) expenses 35,743 20,203 20,249
+-------- -------- --------
+Income (loss) before income taxes (9,732) (2,571) 2,793
+Income tax expense (benefit) 8,432 (900) 977
+-------- -------- --------
+Net income (loss) before Medusa Spar LLC and cumulative
+effect of change in accounting principle (18,164) (1,671) 1,816
+Loss from Medusa Spar LLC, net of tax (8) -- --
+-------- -------- --------
+Income (loss) before cumulative effect of change in
+accounting principle (18,172) (1,671) 1,816
+Cumulative effect of change in accounting principle, net of tax 181 -- --
+-------- -------- --------
+Net income (loss) (17,991) (1,671) 1,816
+Preferred stock dividends 1,277 1,277 1,277
+-------- -------- --------
+Net income (loss) available to common shares $(19,268) $ (2,948) $ 539
+======== ======== ========
+Net income (loss) per common share:
+Basic
+Net income (loss) available to common before cumulative
+effect of change in accounting principle $ (1.42) $ (0.22) $ .04
+Cumulative effect of change in accounting principle, net of tax 0.01 -- --
+-------- -------- --------
+Net income (loss) available to common $ (1.41) $ (0.22) $ .04
+======== ======== ========
+Diluted
+Net income (loss) available to common before cumulative
+effect of change in accounting principle $ (1.42) $ (0.22) $ .04
+Cumulative effect of change in accounting principle, net of tax 0.01 -- --
+-------- -------- --------
+Net income (loss) available to common $ (1.41) $ (0.22) $ .04
+======== ======== ========
+Shares used in computing net income (loss):
+Basic 13,662 13,387 13,273
+======== ======== ========
+Diluted 13,662 13,387 13,366
+======== ======== ========
+The accompanying notes are an integral part of these financial statements.
+47
+CALLON PETROLEUM COMPANY
+CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
+(IN THOUSANDS)
+Unearned Accumulated Total
+Restricted Capital in Other Retained Stock-
+Preferred Common Stock Excess of Comprehensive Earnings holders'
+Stock Stock Compensation Par Value Income (Loss) (Deficit) Equity
+--------- ------ ------------ ---------- ------------- ------------- ---------
+Balances, December 31, 2000 $ 6 $133 $ -- $ 150,040 $ -- $ (13,851) $136,328
+-------- ---- ----- --------- ------- --------- --------
+Comprehensive income:
+Net income -- -- -- -- -- 1,816
+Other comprehensive income -- -- -- -- 5,971 --
+--------
+Total comprehensive income 7,787
+Preferred stock dividend -- -- -- -- -- (1,277) (1,277)
+Shares issued pursuant to employee
+benefit and option plan -- 1 -- 942 -- -- 943
+Employee stock purchase plan -- -- -- 357 -- -- 357
+Tax benefits related to stock
+compensation plans -- -- -- 18 -- -- 18
+Warrants -- -- -- 3,068 -- -- 3,068
+-------- ---- ----- --------- ------- --------- --------
+Balances, December 31, 2001 6 134 -- 154,425 5,971 (13,312) 147,224
+-------- ---- ----- --------- ------- --------- --------
+Comprehensive income:
+Net loss -- -- -- -- -- (1,671)
+Other comprehensive loss -- -- -- -- (6,440) --
+--------
+Total comprehensive loss (8,111)
+Preferred stock dividends -- -- -- -- -- (1,277) (1,277)
+Shares issued pursuant to employee
+benefit and option plan -- 1 -- 770 -- -- 771
+Employee stock purchase plan -- -- -- 79 -- -- 79
+Tax benefits related to stock
+compensation plans -- -- -- (29) -- -- (29)
+Restricted stock -- 3 (826) 1,849 -- -- 1,026
+Warrants -- 1 -- 1,276 -- -- 1,277
+-------- ---- ----- --------- ------- --------- --------
+Balances, December 31, 2002 6 139 (826) 158,370 (469) (16,260) 140,960
+-------- ---- ----- --------- ------- --------- --------
+Comprehensive income:
+Net loss -- -- -- -- -- (17,991)
+Other comprehensive income -- -- -- -- 449 --
+--------
+Total comprehensive loss (17,542)
+Preferred stock dividends -- -- -- -- -- (1,277) (1,277)
+Shares issued pursuant to employee
+benefit and option plan -- 1 -- 427 -- -- 428
+Employee stock purchase plan -- -- -- 127 -- -- 127
+Restricted stock -- (1) 454 (516) -- -- (63)
+Warrants -- -- -- 10,628 -- -- 10,628
+-------- ---- ----- --------- ------- --------- --------
+Balances, December 31, 2003 $ 6 $139 $(372) $ 169,036 $ (20) $ (35,528) $133,261
+======== ==== ===== ========= ======= ========= ========
+The accompanying notes are an integral part of these financial statements.
+48
+CALLON PETROLEUM COMPANY
+CONSOLIDATED STATEMENTS OF CASH FLOWS
+FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
+(IN THOUSANDS)
+2003 2002 2001
+--------- -------- --------
+Cash flows from operating activities:
+Net income (loss) $ (17,991) $ (1,671) $ 1,816
+Adjustments to reconcile net income (loss) to
+cash provided by operating activities:
+Depreciation, depletion and amortization 29,264 27,774 21,709
+Accretion expense 2,884 -- --
+Amortization of deferred costs 6,568 5,521 2,485
+Non-cash loss on early extinguishment of debt 4,423
+Amortization of deferred production payment revenue -- (2,406) (4,830)
+Cumulative effect of change in accounting principle (181) -- --
+Non-cash derivative income -- (9,186) --
+Non-cash mark-to-market commodity derivative contracts 487 708 --
+Non-cash charge related to compensation plans 858 1,267 942
+Deferred income tax expense (benefit) 8,432 (900) 977
+Gain on sale of pipeline -- (2,454) --
+Writedown of Enron derivatives -- -- 9,186
+Changes in current assets and liabilities:
+Accounts receivable, trade (1,438) (4,967) 3,336
+Advance to operators (1,501) (98) 1,131
+Other current assets (1,166) (6) (2)
+Current liabilities 5,185 3,198 (8,782)
+Investment in derivative contracts -- (1,687) --
+Increase in accounts payable and accrued liabilities
+to be refinanced -- -- 9,558
+Change in gas balancing receivable (340) (288) 170
+Change in gas balancing payable (491) (390) 355
+Change in other long-term liabilities (15) 67 (1,749)
+Change in other assets, net (349) (2,315) (1,071)
+--------- -------- --------
+Cash provided (used) by operating activities 34,629 12,167 35,231
+--------- -------- --------
+Cash flows from investing activities:
+Capital expenditures (50,705) (66,023) (113,833)
+Sale of Medusa Spar to Medusa Spar, LLC 24,908 -- --
+Proceeds from sale of pipeline and other facilities 1,500 6,784 --
+Cash proceeds from sale of mineral interests 982 4,492 1,195
+--------- -------- --------
+Cash provided (used) by operating activities (23,315) (54,747) (112,638)
+--------- -------- --------
+Cash flows from financing activities:
+Change in accounts payable and accrued liability to be refinanced (3,861) (5,697) --
+Increase in debt 198,000 109,900 155,000
+Payment on debt (133,000) (58,085) (84,900)
+Restricted cash (63,345) -- --
+Debt issuance costs (3,745) (2,291) (2,374)
+Equity issued related to employee stock plans 127 79 357
+Capital lease (1,320) (1,129) 5,612
+Cash dividends on preferred stock (1,277) (1,277) (1,277)
+--------- -------- --------
+Cash provided (used) by financing activities (8,421) 41,500 72,418
+--------- -------- --------
+Net increase (decrease) in cash and cash equivalents 2,893 (1,080) (4,989)
+Cash and cash equivalents:
+Balance, beginning of period 5,807 6,887 11,876
+--------- -------- --------
+Balance, end of period $ 8,700 $ 5,807 $ 6,887
+========= ======== ========
+The accompanying notes are an integral part of these financial statements.
+49
+CALLON PETROLEUM COMPANY
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+1. ORGANIZATION
+GENERAL
+Callon Petroleum Company ("the Company" or "Callon") was organized under the
+laws of the state of Delaware in March 1994 to serve as the surviving entity in
+the consolidation and combination of several related entities (referred to
+herein collectively as the "Constituent Entities"). The combination of the
+businesses and properties of the Constituent Entities with the Company was
+completed on September 16, 1994 ("Consolidation").
+As a result of the Consolidation, all of the businesses and properties of the
+Constituent Entities are owned (directly or indirectly) by the Company. Certain
+registration rights were granted to the stockholders of certain of the
+Constituent Entities. See Note 7.
+The Company and its predecessors have been engaged in the acquisition,
+development and exploration of crude oil and natural gas since 1950. The
+Company's properties are geographically concentrated in Louisiana, Alabama,
+Texas and offshore Gulf of Mexico.
+2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
+PRINCIPLES OF CONSOLIDATION AND REPORTING
+The Consolidated Financial Statements include the accounts of the Company, and
+its subsidiary, Callon Petroleum Operating Company ("CPOC"). CPOC also has
+subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing,
+Inc. All intercompany accounts and transactions have been eliminated. Certain
+prior year amounts have been reclassified to conform to presentation in the
+current year.
+USE OF ESTIMATES
+The preparation of financial statements in conformity with generally accepted
+accounting principles requires management to make estimates and assumptions that
+affect the reported amounts of assets and liabilities and disclosure of
+contingent assets and liabilities at the date of the financial statements and
+the reported amounts of revenues and expenses during the reporting period.
+Actual results could differ from those estimates.
+ACCOUNTING PRONOUNCEMENTS
+In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement
+of Financial Accounting Standards No. 133 ("SFAS 133"), Accounting for
+Derivative Instruments and Hedging Activities. The Statement establishes
+accounting and reporting standards requiring that every derivative instrument,
+including certain derivative instruments embedded in other contracts, be
+recorded in the balance sheet as either an asset or liability measured at its
+fair value. The Company adopted SFAS 133 effective January 1, 2001. The
+cumulative effect of the accounting change, net of tax, recorded as other
+comprehensive loss was $3.8 million.
+50
+SFAS 133 requires the Company to report changes in the fair value of its
+derivative financial instruments that qualify as cash flow hedges in other
+comprehensive income, a component of stockholders' equity, until realized. See
+Note 6 for a discussion of the Company's derivative financial instruments.
+In June 2001, the FASB issued Statement of Financial Accounting Standards No.
+143, Accounting for Asset Retirement Obligations ("SFAS 143") effective for
+fiscal years beginning after June 15, 2002. SFAS 143 essentially requires
+entities to record the fair value of a liability for obligations associated with
+the retirement of tangible long-lived assets and the associated asset retirement
+costs. Callon adopted the statement on January 1, 2003 resulting in a cumulative
+effect of accounting change of $181,000, net of tax. See Note 8.
+In December 2002, the FASB issued Statement of Financial Accounting Standards
+No. 148 ("SFAS 148"), "Accounting for Stock-Based Compensation-Transition and
+Disclosure -an amendment of SFAS No. 123." SFAS 148 amends SFAS 123, "Accounting
+for Stock-Based Compensation", to provide alternative methods of transition for
+a voluntary change to the fair value based method of accounting for stock-based
+employee compensation. In addition, this statement amends the disclosure
+requirements of SFAS 123 to require disclosures in both annual and interim
+financial statements about the method of accounting for stock-based employee
+compensation and the effect of the method used on the reported results. SFAS 148
+was effective for the year ended December 31, 2002 and for interim financial
+statements commencing in 2003. The adoption of this pronouncement by the Company
+did not have an impact on its financial condition or results of operations. See
+Stock-Based Compensation for related disclosures.
+In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
+Variable Interest Entities, an Interpretation of Accounting Research Bulletin
+(ARB) 51" ("FIN 46"). FIN 46 addresses consolidation by business enterprises of
+variable interest entities ("VIEs"). The primary objective of FIN 46 is to
+provide guidance on the identification of, and financial reporting for, entities
+over which control is achieved through means other than voting rights; such
+entities are known as VIEs. The provisions of FIN 46 are effective immediately
+for these variable interest entities created after January 31, 2003. On December
+24, 2003, the FASB issued a revision to FIN 46 which among other things deferred
+the effective date for certain variable interests created prior to January 31,
+2003. Application is required for interests in special-purpose entities in the
+periods ending after December 15, 2003 and application is required for all other
+types of variable interest entities in the periods ending after March 31, 2004.
+The Company adopted FIN 46, as revised, as of December 31, 2003, which had no
+impact on the financial statements.
+In June 2001, the FASB issued Statement of Financial Accounting Standards No.
+141 ("SFAS 141"), "Business Combinations," which requires the use of the
+purchase method of accounting for business combinations initiated after June 30,
+2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also
+issued Statement of Financial Accounting Standards No. 142 ("SFAS 142"),
+"Goodwill and Other Intangible Assets," which discontinues the practice of
+amortizing goodwill and indefinite lived intangible assets and initiates an
+annual review of impairment. The new standard also requires that all intangible
+assets be aggregated and presented as a separate line item in the balance sheet.
+The adoption of SFAS No. 141 and 142 had no impact on the Company's financial
+position or results of operations. A reporting issue has arisen regarding the
+application of certain provisions of SFAS No. 141 and 142 to companies in the
+oil and gas industry. The issue is whether SFAS No. 141 requires registrants to
+classify the costs of mineral rights associated with extracting oil and gas as
+intangible assets in the balance sheet, apart from other capitalized oil and gas
+property costs, and provide specific footnote disclosures. Historically, the
+Company has included the costs of mineral rights associated with extracting oil
+and gas as
+51
+a component of oil and gas properties. These costs include those to acquire
+contract based drilling and mineral use rights such as delay rentals, lease
+bonuses, commissions and brokerage fees, and other leasehold costs.
+The Emerging Issues Task Force ("EITF") has added the treatment of oil and gas
+mineral rights to an upcoming agenda, which may result in a change in the
+classification of these amounts, as described above. The Company will continue
+to classify its oil and gas leasehold costs as tangible oil and gas properties
+until further guidance is provided. The Company's cash flows and results of
+operations would not be affected since such intangible assets would continue to
+be depleted and assessed for impairment in accordance with full cost accounting
+rules, as allowed by SFAS No. 142. Further, the Company believes that the
+amounts that would be classified as intangible assets as of December 31, 2003
+and 2002 would be immaterial.
+The Company follows the asset and liability method of accounting for deferred
+income taxes prescribed by Statement of Financial Accounting Standards No. 109
+("SFAS 109") "Accounting for Income Taxes". The statement provides for the
+recognition of a deferred tax asset for deductible temporary timing differences,
+capital and operating loss carryforwards, statutory depletion carryforward and
+tax credit carryforwards, net of a "valuation allowance". The valuation
+allowance is provided for that portion of the asset, for which it is deemed more
+likely than not, that it will not be realized. See Note 3.
+PROPERTY AND EQUIPMENT
+The Company follows the full cost method of accounting for oil and gas
+properties whereby all costs incurred in connection with the acquisition,
+exploration and development of oil and gas reserves, including certain overhead
+costs, are capitalized. Such amounts include the cost of drilling and equipping
+productive wells, dry hole costs, lease acquisition costs, delay rentals,
+interest capitalized on unevaluated leases and other costs related to
+exploration and development activities. Payroll and general and administrative
+costs capitalized include salaries and related fringe benefits paid to employees
+directly engaged in the acquisition, exploration and/or development of oil and
+gas properties as well as other directly identifiable general and administrative
+costs associated with such activities. Such capitalized costs ($13.2 million in
+2003, $9.6 million in 2002 and $10.0 million in 2001) do not include any costs
+related to production or general corporate overhead. Costs associated with
+unevaluated properties, including capitalized interest on such costs, are
+excluded from amortization. Unevaluated property costs are transferred to
+evaluated property costs at such time as wells are completed on the properties,
+the properties are sold or management determines that these costs have been
+impaired.
+Costs of properties, including future development and net future site
+restoration, dismantlement and abandonment costs, which have proved reserves and
+those which have been determined to be worthless, are depleted using the
+unit-of-production method based on proved reserves. If the total capitalized
+costs of oil and gas properties, net of accumulated amortization and deferred
+taxes relating to oil and gas properties, exceed the sum of (1) the estimated
+future net revenues from proved reserves at current prices and discounted at 10%
+and (2) the lower of cost or market of unevaluated properties (the full cost
+ceiling amount), net of tax effects, then such excess is charged to expense
+during the period in which the excess occurs. See Note 9.
+Upon the acquisition or discovery of oil and gas properties, management
+estimates the future net costs to be incurred to dismantle, abandon and restore
+the property using available geological, engineering and regulatory data. Such
+cost estimates are periodically updated for changes in conditions and
+requirements. Such estimated amounts are considered as part of the full cost
+pool subject to amortization upon acquisition
+52
+or discovery. Until January 1, 2003, such costs were capitalized as oil and gas
+properties as the actual restoration, dismantlement and abandonment activities
+took place. As discussed above under Accounting Pronouncements, beginning
+January 1, 2003, the Company changed the method for which we account for such
+costs upon adoption of SFAS 143 and these costs are included in the full cost
+pool. For purposes of the full cost ceiling test, the Company nets the Asset
+Retirement Obligation liability against the net capitalized costs of oil and gas
+properties and includes cash outflows associated with asset retirement
+obligations in the calculation of the full cost ceiling amount.
+Depreciation of other property and equipment is provided using the straight-line
+method over estimated lives of three to 20 years. Depreciation of pipeline and
+other facilities is provided using the straight-line method over estimated lives
+of 15 to 27 years.
+SALE OF PRODUCTION PAYMENT INTEREST
+In June 1999, the Company acquired a working interest in the Mobile Block 864
+Area where the Company already owned an interest. Concurrent with this
+acquisition, the seller received a volumetric production payment, valued at
+approximately $14.8 million, from production attributable to a portion of the
+Company's interest in the area over a 39-month period. The Company recorded a
+liability associated with the sale of this production payment interest because a
+substantial obligation for future performance existed. Under the terms of the
+sale, the Company was obligated to deliver the production volumes free and clear
+of royalties, lease operating expenses, production taxes and all capital costs.
+The production payment was amortized, beginning in June 1999, to oil and gas
+sales on the units-of-production method as associated hydrocarbons were
+delivered, and expired in July 2002.
+NATURAL GAS IMBALANCES
+The Company follows the entitlement method of accounting for its proportionate
+share of gas production on a well-by-well basis, recording a receivable to the
+extent that a well is in an "undertake" position and conversely recording a
+liability to the extent that a well is in an "overtake" position.
+DERIVATIVES
+The Company uses derivative financial instruments for price protection purposes
+on a limited amount of its future production and does not use them for trading
+purposes. Such derivatives are accounted for under SFAS 133 (See Note 6).
+ACCOUNTS RECEIVABLE
+Accounts receivable consists primarily of accrued oil and gas production
+receivables. The balance in the reserve for doubtful accounts included in
+accounts receivable was $103,000 and $143,000 at December 31, 2003 and 2002,
+respectively. Net charge offs were $40,000 in 2003 and net recoveries were
+$75,000 in 2002. There were no provisions to expense in the three-year period
+ended December 31, 2003.
+ACCOUNTS PAYABLE AND ACCRUED LIABILITIES TO BE REFINANCED
+These amounts included in the Consolidated Balance Sheet represent capital
+expenditures in accounts payable and accrued liabilities that were refinanced
+with the availability under the Company's senior secured credit facility
+subsequent to December 31, 2002. Amounts in 2003 were classified as short term
+because of the maturity of the Credit Facility on June 30, 2004.
+53
+STOCK-BASED COMPENSATION
+The Company's pro forma net income (loss) and net income (loss) per share of
+common stock for the 12-month periods ended December 31, 2003, 2002 and 2001 had
+compensation costs been recorded using the fair value method in accordance with
+SFAS 123, as amended by SFAS 148 are presented below pursuant to the disclosure
+requirements of SFAS 148 (in thousands except per share data):
+2003 2002 2001
+-------- ------- -------
+(IN THOUSANDS, EXCEPT PER SHARE DATA)
+Net income (loss) available to common shares,
+as reported $(19,268) $(2,948) $ 539
+Stock-based compensation expense included
+in net income as reported, net of tax 17 270 397
+Deduct: Total stock-based
+compensation expense under fair
+value based method, net of tax (202) (907) (1,775)
+-------- ------- -------
+Pro forma net income (loss) available to
+common shares $(19,453) $(3,585) $ (839)
+======== ======= =======
+Basic earnings (loss) per share: As Reported (1.41) (.22) .04
+Pro Forma (1.42) (.27) (.06)
+Diluted earnings (loss) per share: As Reported (1.41) (.22) .04
+Pro Forma (1.42) (.27) (.06)
+See Note 11 for descriptions and additional disclosures related to the plans.
+MAJOR CUSTOMERS
+The Company's production is sold generally on month-to-month contracts at
+prevailing prices. The following table identifies customers to whom it sold a
+significant percentage of its total oil and gas production during each of the
+12-month periods ended:
+DECEMBER 31,
+------------------
+2003 2002 2001
+---- ---- ----
+Petrocom Energy Group, Ltd. 4% 4% --
+Dynegy 5% 7% 8%
+Prior Energy Corporation 20% -- 20%
+Reliant Energy Services 28% 70% 49%
+Louis Dreyfus Energy Services 27% -- --
+Because alternative purchasers of oil and gas are readily available, the Company
+believes that the loss of any of these purchasers would not result in a material
+adverse effect on its ability to market future oil and gas production.
+STATEMENTS OF CASH FLOWS
+For purposes of the Consolidated Financial Statements, the Company considers all
+highly liquid investments purchased with an original maturity of three months or
+less to be cash equivalents.
+54
+The Company paid no federal income taxes for the three years ended December 31,
+2003. During the years ended December 31, 2003, 2002 and 2001, the Company made
+cash payments for interest of $27,913,000, $25,507,000 and $16,441,000,
+respectively.
+PER SHARE AMOUNTS
+Basic income or loss per common share was computed by dividing net income or
+loss by the weighted average number of shares of common stock outstanding during
+the year. Diluted income or loss per common share was determined on a weighted
+average basis using common shares issued and outstanding adjusted for the effect
+of stock options considered common stock equivalents computed using the treasury
+stock method and the effect of the convertible preferred stock (if dilutive).
+The conversion of the preferred stock was not included in any annual calculation
+due to its antidilutive effect on diluted income or loss per common share. In
+addition, below are the shares relating to stock options, warrants and
+restricted stock that were not included in diluted shares for the twelve-month
+periods ended December 31, 2003 and 2002 due to the fact that the Company had a
+loss for these periods. The Company had net income for the period ended December
+31, 2001 and therefore had no such shares for this period.
+TWELVE MONTHS ENDED DECEMBER 31,
+--------------------------------
+(IN THOUSANDS)
+2003 2002
+---- ----
+Stock options 63 13
+Warrants 424 372
+Restricted Stock 248 122
+A reconciliation of the basic and diluted per share computation is as follows
+(in thousands, except per share amounts):
+2003 2002 2001
+-------- ------- -------
+(a) Net income (loss) available to common shares $(19,268) $(2,948) $ 539
+Preferred dividends assuming conversion of
+preferred stock (if dilutive) -- -- --
+-------- ------- -------
+(b) Income (loss) available to common shares assum-
+ing conversion of preferred stock (if dilutive) $(19,268) $(2,948) $ 539
+======== ======= =======
+(c) Weighted average shares outstanding 13,662 13,387 13,273
+Dilutive impact of stock options -- -- 27
+Dilutive impact of restricted stock -- -- --
+Dilutive impact of warrants -- -- 66
+Convertible preferred stock (if dilutive) -- -- --
+-------- ------- -------
+(d) Total diluted shares 13,662 13,387 13,366
+======== ======= =======
+Stock options and warrants excluded due to the
+exercise price being greater than the stock price 2,297 2,250 1,438
+Basic income (loss) per share (a/c) $ (1.41) $ (.22) $ .04
+Diluted income (loss) per share (b/d) $ (1.41) $ (.22) $ .04
+55
+FAIR VALUE OF FINANCIAL INSTRUMENTS
+Fair value of cash, cash equivalents, accounts receivable, accounts payable, the
+capital lease and the senior secured credit facility approximates book value at
+December 31, 2003 and 2002. Fair value of long-term debt (specifically, the
+10.125%, the 10.25%, the 11% Senior Subordinated Notes and the 12% loans) have
+an estimated fair value of 100% of face value at December 31, 2003.
+3. INCOME TAXES
+The Company has recorded a deferred tax asset at December 31, 2003 and 2002 and
+a valuation allowance at December 31, 2003 as follows:
+DECEMBER 31,
+---------------------
+2003 2002
+-------- --------
+(IN THOUSANDS)
+Federal net operating loss carryforwards $ 61,805 $ 42,464
+Statutory depletion carryforward 4,255 4,251
+Temporary differences:
+Oil and gas properties (66,725) (39,159)
+Pipeline and other facilities -- (299)
+Non-oil and gas property (16) (30)
+Other 1,620 1,540
+SFAS 143-Asset Retirement Obligations 10,563 --
+-------- --------
+Total tax asset 11,502 8,767
+Valuation allowance (11,502) --
+-------- --------
+Net tax asset $ -- $ 8,767
+======== ========
+SFAS 109 provides for the weighing of positive and negative evidence in
+determining whether it is more likely than not that a deferred tax asset is
+recoverable. The Company has incurred losses in 2002 and 2003 and has losses on
+an aggregate basis for the three-year period ended December 31, 2003. However,
+as discussed in Note 5, in December 2003 the Company refinanced nearly all its
+highest cost debt, incurring an early extinguishment loss of $5.6 million, but
+achieving significant interest savings in the future. In addition, as discussed
+in Note 5, the first two of the Company's deepwater projects began production in
+November 2003, which is expected to result in a significant increase in 2004
+production as compared to 2003. Nevertheless, relevant accounting guidance
+suggests that a recent history of cumulative losses constitutes significant
+negative evidence, and that future expectations about income are overshadowed by
+such recent losses. As a result, the Company established a valuation allowance
+of $11.5 million as of December 31, 2003. If the Company achieves profitable
+operations in 2004, the Company expects it will reverse a portion of the
+valuation allowance in an amount at least sufficient to eliminate any tax
+provision in that period.
+56
+Below is a reconciliation of the reported amount of income tax expense
+attributable to continuing operations for the year to the amount of income tax
+expense that would result from applying domestic federal statutory tax rates to
+pretax income from continuing operations.
+YEAR ENDED DECEMBER 31,
+-----------------------
+2003 2002 2000
+---- ---- ----
+Income tax expense (benefit) computed at the statutory
+federal income tax rate (35%) (35%) 35%
+Change in valuation allowance 118% -- --
+Write off of NOL's 4% -- --
+---- ---- ----
+Effective income tax rate 87% (35%) 35%
+==== ==== ====
+The Company has significant state net operating loss carryforwards that are not
+included in the deferred tax asset above, as the Company does not anticipate
+generating taxable state income in the states in which these loss carryforwards
+apply. The Company has very limited state taxable income as primarily all of its
+revenue is generated in federal waters not subject to state income taxes.
+4. OTHER COMPREHENSIVE INCOME
+A recap of the Company's 2003, 2002 and 2001 comprehensive income (net of tax)
+is shown below (in thousands):
+YEARS ENDED DECEMBER 31,
+------------------------------
+2003 2002 2001
+-------- -------- --------
+Other comprehensive income (loss):
+Cumulative effect of change in
+accounting principle $ -- $ -- $ (3,764)
+Change in derivatives fair value 449 (469) 9,735
+Amortization of Enron derivatives -- (5,971) --
+-------- -------- --------
+Total other comprehensive income (loss) $ 449 $ (6,440) $ 5,971
+======== ======== ========
+57
+5. LONG-TERM DEBT
+Long-term debt consisted of the following at:
+DECEMBER 31,
+2003 2002
+--------- ---------
+(IN THOUSANDS)
+Senior Secured Credit Facility $ 30,000* $ 65,000
+Senior Subordinated Notes (due 2004) - these notes were
+retired with restricted cash on 01/08/2004:
+10.125% notes net of discount 21,772* 20,086
+10.250% notes 40,000* 40,000
+12% Senior Loans (due 2005) net of discount 9,490 87,020
+11% Senior Subordinated Notes (due 2005) 33,000 33,000
+9.75% Senior Loans (due 2010) net of discount 170,684 --
+Capital Lease 3,162 4,483
+--------- ---------
+Total Long-term Debt 308,108* 249,589
+Less current portion 93,223* 1,320
+--------- ---------
+Long-term portion $214,885 $248,269
+========= =========
+* $62.9 million of 2004 senior subordinated notes are in this
+current portion and were retired on January 8, 2004. Total Long-term
+Debt after retirement of the 2004 notes was $245.2 million. The
+senior secured credit facility comprises $30 million of the current
+portion. It is expected that the maturity date of the facility will
+be renegotiated and extended or the facility will be replaced.
+SENIOR SECURED CREDIT FACILITY. The Company negotiated its senior secured credit
+facility effective October 31, 2000 with Wachovia Bank, National Association,
+formerly First Union National Bank. Borrowings under the senior secured credit
+facility are secured by mortgages covering substantially all of the Company's
+producing oil and gas properties. On June 30, 2002 the Company amended the
+senior secured credit facility to increase availability under the revolving
+borrowing base from $50 million to $75 million under a dual tranche loan. The
+Tranche A revolver bears interest at 0.25% to 0.75% above a defined base rate
+depending on utilization of the borrowing base or, at the option of the Company,
+LIBOR plus 2% to 2.5% based on utilization of the borrowing base and has a
+maximum aggregate credit amount of $45 million until Tranche B is retired. The
+range of interest rates on the Tranche A revolver was 3.12% to 5.00% for the 12
+months ended December 31, 2003. The Tranche B part of the facility bears an
+interest rate of 15% and has an aggregate maximum credit amount of $30 million.
+The weighted average interest rate for the senior secured credit facility debt
+outstanding at December 31, 2003 and 2002 was 15% and 9%, respectively. Under
+the senior secured credit facility, a commitment fee of 0.25% or 0.375% per
+annum, depending on the amount of the unused portion of the borrowing base, is
+payable quarterly.
+There were no borrowings outstanding on Tranche A and there was $30 million
+outstanding against Tranche B at December 31, 2003. On December 21, 2003, the
+Company exercised its right to call the Tranche B loan with a 30-day notice and
+on January 21, 2004, the Company drew $27 million under Tranche A and redeemed
+the Tranche B principal plus a 1% call premium. Repayment of Tranche B cancelled
+any future credit amounts available under Tranche B. Currently, the facility
+provides for a $45.0 million borrowing base under Tranche A which is adjusted
+periodically on the basis of the discounted present value of future net cash
+flows attributable to our proved producing oil and gas reserves
+58
+and other factors deemed relevant by the lenders. The borrowing base for Tranche
+A is currently being reviewed by the lenders and could be increased due to the
+Company's proved producing reserves increasing as a result of the Medusa and
+Habanero fields commencing production in the fourth quarter of 2003. This
+facility expires on June 30, 2004 and the Company is currently reviewing options
+to extend the maturity date or to replace the facility with one that is similar
+or with more favorable terms. Borrowings under the credit facility are
+classified as current at December 31, 2003.
+SENIOR SUBORDINATED NOTES (DUE 2004). Covenant defeasance was exercised under
+the indentures for the 10.125% and 10.25% notes on December 8, 2003 and a
+required 30-day redemption notice was distributed to holders. The funds
+necessary to redeem the notes were placed in trust, from the net proceeds of the
+new 9.75% loans and the trustee paid the holders of the notes on January 8,
+2004. The terms of the covenant defeasance that were exercised did not meet the
+requirements for legal defeasance under SFAS 140, "Accounting for Transfers and
+Servicing of Financial Instruments and Extinguishment of Debt", and therefore
+these notes are considered outstanding at December 31, 2003. The funds in trust
+were classified on the Company's December 31, 2003 consolidated balance sheet as
+restricted cash.
+On September 15, 2002, $36 million of the Company's 10.125% Senior Subordinated
+Notes ("Notes") that were issued on July 31, 1997, were due. The holders of
+$22.9 million of the Notes consented to an extension of such Notes until July
+31, 2004. The Company granted 274,980 warrants (with a fair market value of
+approximately $1.3 million) to purchase Common Stock of the Company and paid
+consent fees in the amount of $2.3 million to the holders of the Notes that
+granted the extensions. These amounts were treated as an additional discount on
+the debt. The warrants have a term of five years and an exercise price of $0.01.
+The holders of the Notes had exercised approximately 116,000 warrants as of
+December 31, 2003. The holders of the Notes that did not consent to the
+extension were paid on the maturity date in September 2002. Interest on the
+Notes was payable quarterly, on March 15, June 15, September 15, and December 15
+of each year.
+The Company accounted for the extension of the $22.9 million in Notes described
+above as an extinguishment of the Notes and the issuance of new securities were
+recorded at a fair value of $19.3 million. The net loss on extinguishment was
+not significant. Costs deferred with the extensions were being amortized through
+July 2004. As a result of the redemption of the Notes on January 8, 2004, the
+unamortized balance of the discount and the deferred costs of $1.1 million will
+be expensed during the first quarter of 2004 as a loss on early extinguishment
+of debt.
+On July 15, 1999, the Company completed the sale of $40 million of Senior
+Subordinated Notes due 2004 at 10.25%. These notes were not entitled to any
+mandatory sinking fund payments and were subject to redemption at the Company's
+option at par plus unpaid interest at any time after March 15, 2001. Interest
+was paid quarterly. The notes were redeemed on January 8, 2004. These notes are
+classified as current at December 31, 2003.
+12% SENIOR UNSECURED CREDIT FACILITY (DUE 2005). In July 2001, the Company
+entered into a $95 million senior unsecured credit facility with a private
+lender. The Company borrowed $45 million upon closing of the loan and borrowed
+the remaining $50 million in December 2001. The loans bear interest at the rate
+of 12% per year. Under the terms of the agreement, Callon also issued warrants
+to purchase, at a nominal exercise price, 265,210 shares of its Common Stock
+(fair value of $3.1 million) and conveyed an overriding royalty interest equal
+to 2% of the Company's net interest in four existing deepwater discoveries (fair
+value of $5.9 million). These amounts were treated as an additional discount on
+the debt. The warrants and the overriding royalty interest were earned by the
+lender based on the ratio of the
+59
+amount of the loan proceeds advanced to the total loan facility amount. The
+loans will mature March 31, 2005 and have an effective interest rate of
+approximately 16%.
+The Company recorded these borrowings at a value of $84 million net of discount.
+Deferred costs associated with the loans are being amortized through March 2005.
+Upon redemption of $85 million of the loans on December 30, 2003 the pro rata
+portion of the unamortized balance of the discount and the associated deferred
+costs in the amount of $4.4 million and a 1% call premium of $850,000 were
+expensed during the fourth quarter of 2003 as a loss on early extinguishment of
+debt.
+11% SENIOR SUBORDINATED NOTES (DUE 2005). On October 26, 2000 the Company
+completed the sale of $33 million of 11% Senior Subordinated Notes due December
+15, 2005. The Company netted $31.5 million from the offering after deducting the
+underwriters' discount and offering expenses.
+9.75% SENIOR LOANS (DUE 2010). In December 2003 the Company borrowed $185
+million pursuant to a senior unsecured credit facility. The loans under the
+credit facility have a stated interest rate of 9.75% and a seven-year maturity.
+The net proceeds of $181.3 million were used to redeem $22.9 million of 10.125%
+senior subordinated notes due July 31, 2004, $40 million of 10.25% senior
+subordinated notes due September 15, 2004 and $85 million of our 12% loan due
+March 31, 2005 issued pursuant to a senior unsecured credit agreement dated July
+29, 2001 plus a 1% pre-payment premium of $850,000, and to reduce the balance
+outstanding under the Company's senior secured credit facility. In conjunction
+with the new senior unsecured notes, the Company issued detachable warrants to
+purchase 2.775 million of our common stock at an exercise price of $10 per
+share. The warrants were valued at $10.6 million and were treated as an
+additional discount on the debt. This senior unsecured debt matures December 8,
+2010 and has an effective interest rate of 11.4%. The Company recorded the
+issuance of these new securities at a fair value of $171 million. Deferred costs
+of $14 million associated with the notes will be amortized over the life of the
+notes.
+REMAINING MATURITIES FOR UNSECURED DEBT. Our remaining maturities for unsecured
+debt consist of the $185 million in 9.75% loans due 2010, $10 million of the 12%
+loans with a due date of March 31, 2005 and $33 million of 11% senior
+subordinated notes with a due date of December 15, 2005. These 2005 maturities
+will be retired by our primary sources of capital which are cash flows from
+operations, borrowings from financial institutions and the sale of debt and
+equity securities.
+CAPITAL LEASE. In December 2001, the Company entered into a 10-year gas
+processing agreement associated with a production facility on Callon's Mobile
+Block 952 field with Hanover Compression Limited Partnership, which is being
+accounted for as a capital lease. Total minimum obligations are $8.4 million
+with interest representing approximately $2.8 million and the present value
+minimum obligations were $5.6 million ($1.2 million current).
+RESTRICTIVE COVENANTS. The senior secured credit facility, the senior
+subordinated debt and the senior unsecured credit facilities contain various
+covenants including restrictions on additional indebtedness and payment of cash
+dividends as well as maintenance of certain financial ratios. The Company was in
+compliance with these covenants at December 31, 2003.
+60
+FUTURE MINIMUM LEASE PAYMENTS AND DEBT MATURITIES (IN THOUSANDS) ARE AS FOLLOWS:
+CAPITAL LEASE
+YEAR PAYMENTS DEBT
+---- -------- ----
+2004 $1,890 $ 92,915*
+2005 822 43,000
+2006 439 --
+2007 348 --
+2008 228 --
+Thereafter 694 185,000
+* These maturities consist of $62.9 million of senior subordinated notes which
+were retired on January 8, 2004 and $30 million under the senior secured credit
+facility which matures June 30, 2004 and which the Company expects will be
+renegotiated and extended or replaced with a new facility.
+6. DERIVATIVES
+The Company periodically uses derivative financial instruments to manage oil and
+gas price risk. Settlements of gains and losses on commodity price contracts are
+generally based upon the difference between the contract price or prices
+specified in the derivative instrument and a NYMEX price or other cash or
+futures index price.
+In 2003 and 2002, the Company purchased and sold various put options and call
+options and elected not to designate these derivative financial instruments as
+hedges and accordingly, the changes in fair value of these contracts were
+recorded through earnings. A loss of approximately $666,000 and $708,000 was
+recognized for the twelve month periods ended December 31, 2003 and 2002,
+respectively. The fair value of the open contracts at December 31, 2003 was a
+current liability of $134,640. At December 31, 2002 the fair value was a current
+asset of $352,500.
+During 2002, the Company entered into costless natural gas collar contracts in
+effect for February 2003 through October 2003. These agreements were for volumes
+of 275,000 Mcf per month with an average ceiling price of $4.79 and a floor
+price of $3.52. These contracts were accounted for as cash flow hedges under
+SFAS 133. The fair value of these collar contracts at December 31, 2002 was
+recorded on the balance sheet as a liability of $721,350. The Company recognized
+a reduction of $2,932,000 in oil and gas sales related to the settlements of
+such collars for the 12 months ended December 31, 2003.
+During 2003, the Company entered into additional costless natural gas collar
+contracts in effect for May 2003 through October 2003. These agreements were for
+volumes of 200,000 Mcf per month with a ceiling price of $5.80 and a floor price
+of $5.00. The Company elected not to designate these derivative financial
+instruments as hedges and accordingly, the changes in fair value of these
+contracts were recorded through earnings. For the twelve month period ended
+December 31, 2003, the Company recognized a gain of approximately $131,600.
+In 2001, the Company entered into derivative contracts for 2002 production with
+Enron North America Corp. ("Enron"). In the fourth quarter of 2001, the Company
+charged to expense (non-cash) $9.2 million representing the fair market value of
+these derivatives as of September 30, 2001. As the contracts matured, the
+Company recorded non-cash revenue each month. For the twelve month period ended
+December 31, 2002, the Company recorded approximately $9.2 million, as non-cash
+oil and gas revenues.
+61
+Also, in the second quarter of 2002, the Company completed the sale of its
+claims against Enron for $2.5 million and reported a pre-tax gain of that
+amount.
+In the fourth quarter of 2003, Callon entered into two natural gas collar
+contracts which are listed below:
+Collars
+Volumes per Quantity Floor Ceiling
+Product Month Type Price Price Period
+----------- ----------- -------- ------- ------- ----------
+Natural Gas 100,000 MMBtu $ 5.25 $7.25 12/03-03/04
+Natural Gas 100,000 MMBtu $ 5.00 $7.20 01/04-03/04
+These contracts are accounted for as cash flow hedges under SFAS 133. The
+Company recognized an increase of $52,500 in oil and gas sales related to the
+settlements of such collars in the twelve month period ended December 31, 2003.
+The fair value of these collar contracts at December 31, 2003 was recorded on
+the balance sheet as a liability in the amount of $30,400.
+In the first quarter of 2004, Callon entered into various derivative contracts
+which are listed in the table below:
+Swaps
+Volumes per Quantity
+Product Month Type Average Period
+--------- ----------- -------- --------- -----------
+Oil 30,000 Bbls $ 31.29 02/04-01/05
+Oil 15,000 Bbls $ 30.00 04/04-03/05
+Oil 15,000 Bbls $ 30.00 07/04-12/04
+Collars
+Average Average
+Volumes per Quantity Floor Ceiling
+Product Month Type Price Price Period
+----------- ----------- -------- --------- -------- -----------
+Oil 45,000 Bbls $ 29.33 $ 32.17 02/04-01/05
+Oil 15,000 Bbls $ 30.00 $ 32.50 02/04-10/04
+Natural Gas 500,000 MMBtu $ 5.00 $ 6.08 04/04-11/04
+Natural Gas 100,000 MMBtu $ 5.00 $ 5.60 06/04-11/04
+Natural Gas 300,000 MMBtu $ 5.00 $ 6.91 12/04-03/05
+These contracts will be accounted for as cash flow hedges under SFAS 133.
+7. COMMITMENTS AND CONTINGENCIES
+As described in Note 10, abandonment trusts (the "Trusts") have been established
+for future abandonment obligations of those oil and gas properties of the
+Company burdened by a net profits interest. The management of the Company
+believes the Trusts will be sufficient to offset those future abandonment
+liabilities; however, the Company is responsible for any abandonment expenses in
+excess of the Trusts' balances. As of December 31, 2003, total estimated site
+restoration, dismantlement and abandonment costs were approximately $7.4
+million, net of expected salvage value. Substantially all such costs are
+expected to be funded through the Trusts' funds, all of which will be accessible
+to the Company when abandonment work begins. In addition, as a working interest
+owner and/or operator of oil and gas properties, the Company is responsible for
+the cost of abandonment of such properties. See Notes 2 and 8.
+62
+From time to time, the Company, as part of the Consolidation and other capital
+transactions, entered into registration rights agreements whereby certain
+parties to the transactions are entitled to require the Company to register
+common stock of the Company owned by them with the Securities and Exchange
+Commission for sale to the public in firm commitment public offerings and
+generally to include shares owned by them, at no cost, in registration
+statements filed by the Company. Costs of the offering will not include broker's
+discounts and commissions, which will be paid by the respective sellers of the
+common stock.
+The Company is involved in various claims and lawsuits incidental to its
+business. In the opinion of management, the ultimate liability thereunder, if
+any, will not have a material adverse effect on the financial position or
+results of operations of the Company.
+The Company may be required to retroactively pay royalties to the Minerals
+Management Service on one of the Company's properties which could reduce
+revenues and reserves. The Company's Medusa deepwater property is eligible for
+royalty suspensions pursuant to the Deep Water Royalty Relief Act. However, the
+federal offshore leases covering this property contains "price threshold"
+provisions for oil and gas prices. Under this "price threshold" provision, if
+the average monthly New York Mercantile Exchange (NYMEX) sales price for oil or
+gas during a fiscal year exceeds the price threshold for oil or gas,
+respectively, then royalties on the associated production must be paid to the
+Minerals Management Service (MMS) at the rate stipulated in the lease. The price
+thresholds are adjusted annually by the implicit price deflator for the GDP. The
+determination of whether or not royalties are due as a result of the average
+NYMEX price exceeding the price threshold is made during the first quarter of
+the succeeding year. Any royalty payments due must be made shortly after this
+determination is made. If a royalty payment is due for all production during a
+year as a result of exceeding the price threshold, the lessee is required to
+make monthly royalty payments during the succeeding fiscal year for the
+succeeding year's production. If at the end of any year the average NYMEX price
+is below the price threshold, the lessee can apply for a refund for any
+associated royalties paid during that year and the lessee will not be required
+to pay royalties monthly during the succeeding year for the succeeding year's
+production.
+The thresholds and the average NYMEX prices are calculated by the MMS. The
+average NYMEX price for 2003 was $31.08 per barrel of oil and $5.49 per MMBtu of
+natural gas. For the year ended December 31, 2003 the thresholds were $32.77 per
+barrel of oil and $4.10 per MMBtu of natural gas, subject to finalization of the
+adjustment for the 2003 GDP implicit price deflator. As a result the Company
+will pay royalties related to 2003 gas production for Medusa, which commenced
+production in late November 2003 and will make monthly royalty payments for 2004
+gas production during 2004. The actual liability for 2004 oil royalties, if any,
+cannot be determined until after the end of 2004.
+In the year succeeding the year in which any of the Company's properties became
+subject to royalties as the result of the average NYMEX price exceeding the
+price threshold, the portion of reserves attributable to potential future
+royalties would not be included in a year-end reserve report. However, if the
+average NYMEX prices were below the price thresholds in subsequent years, our
+reserves would be increased to reflect reserves previously attributed to future
+royalties. As a result, reported oil and gas reserves could materially increase
+or decrease, depending on the relation of price thresholds versus the average
+NYMEX prices. The reduction in revenues resulting from an obligation to pay
+these royalties and subsequent reduction of proved reserves could have a
+material adverse effect on the Company's results of operations and financial
+condition. The Company's reserve report as of December 31, 2003 excluded gas
+reserves for Medusa that are subject to MMS royalties as a result of the average
+2003 NYMEX price for gas exceeding the price threshold. Oil reserves in this
+reserve report were not impacted since the 2003 average NYMEX price was below
+the threshold.
+63
+The Company's activities are subject to federal, state and local laws and
+regulations governing environmental quality and pollution control. Although no
+assurances can be made, the Company believes that, absent the occurrence of an
+extraordinary event, compliance with existing federal, state and local laws,
+rules and regulating the release of materials in the environment or otherwise
+relating to the protection of the environment will not have a material effect
+upon the capital expenditures, earnings or the competitive position of the
+Company with respect to its existing assets and operations. The Company cannot
+predict what effect additional regulation or legislation, enforcement polices
+thereunder, and claims for damages to property, employees, other persons and the
+environment resulting from the Company's operations could have on its
+activities.
+8. ASSET RETIREMENT OBLIGATIONS
+As discussed in Note 2, the Company adopted SFAS 143 on January 1, 2003. The
+impact of adopting the statement resulted in a gain of $181,000, net of tax,
+which is reported as a cumulative effect of change in accounting principle.
+Approximately $30.3 million was recorded as the present value of asset
+retirement obligations on January 1, 2003 with the adoption of SFAS 143 related
+to the Company's oil and gas properties. Interest is accreted on this amount and
+reported as accretion expense in the Consolidated Statements of Operations.
+Assets, primarily short-term U.S. Government securities, of approximately $7.4
+million at December 31, 2003, are recorded as restricted investments. These
+assets are held in abandonment trusts dedicated to pay future abandonment costs
+of oil and gas properties in which the Company has sold a net profits interest.
+If there is any excess of trust assets over abandonment costs, the excess will
+be distributed to the net profits interest owners.
+The following table summarizes the activity for the Company's asset retirement
+obligation:
+TWELVE MONTHS ENDED
+DECEMBER 31, 2003
+-------------------
+Asset retirement obligation at beginning of period $ --
+Liability recognized in transition 30,251
+Accretion expense 2,884
+Net profits interest accretion 371
+Liabilities incurred 3,649
+Liabilities settled (2,847)
+Revisions to estimate (617)
+-------
+Asset retirement obligation at end of period 33,691
+Less: current retirement obligation (8,571)
+-------
+Long-term retirement obligation $25,120
+=======
+Pro forma net income and earnings per share are not presented for the 12 months
+ended December 31, 2002 or 2001 because the pro forma application of SFAS 143 to
+the prior periods would not result in pro forma net income and earnings per
+share materially different from the actual amounts reported for the periods in
+the accompanying Consolidated Statements of Operations.
+64
+9. OIL AND GAS PROPERTIES
+The following table discloses certain financial data relating to the Company's
+oil and gas activities, all of which are located in the United States.
+YEARS ENDED DECEMBER 31,
+----------------------------------------
+2003 2002 2001
+--------- --------- ---------
+(IN THOUSANDS)
+Capitalized costs incurred:
+Evaluated Properties-
+Beginning of period balance $ 762,918 $ 704,937 $ 589,549
+Property acquisition costs 1,154 1,471 1,713
+Exploration costs 21,390 17,851 85,782
+Development costs 33,972 43,151 34,980
+SFAS 143-Asset Retirement Obligation 18,002 -- --
+Medusa Spar transaction (33,542) -- --
+Sale of mineral interests (982) (4,492) (7,087)
+--------- --------- ---------
+End of period balance $ 802,912 $ 762,918 $ 704,937
+========= ========= =========
+Unevaluated Properties (excluded from
+amortization) -
+Beginning of period balance $ 40,997 $ 37,560 $ 47,653
+Additions 5,228 5,802 8,760
+Capitalized interest 4,862 5,289 4,879
+Transfers to evaluated (16,836) (7,654) (23,732)
+--------- --------- ---------
+End of period balance $ 34,251 $ 40,997 $ 37,560
+========= ========= =========
+Accumulated depreciation, depletion
+and amortization-
+Beginning of period balance $ 426,254 $ 399,339 $ 378,589
+Provision charged to expense 28,195 26,915 20,750
+Cumulative effect of change in accounting
+principle (7,449) -- --
+--------- --------- ---------
+End of period balance $ 447,000 $ 426,254 $ 399,339
+========= ========= =========
+Unevaluated property costs, primarily lease acquisition costs incurred at
+federal lease sales, unevaluated drilling costs, capitalized interest and
+general and administrative costs being excluded from the amortizable evaluated
+property base, consisted of $8.6 million incurred in 2003, $7.1 million incurred
+in 2002 and $18.5 million incurred in 2001 and prior. These costs are directly
+related to the acquisition and evaluation of unproved properties and major
+development projects. The excluded costs and related reserves are included in
+the amortization base as the properties are evaluated and proved reserves are
+established or impairment is determined. The Company expects that the majority
+of these costs will be evaluated over the next three to five-year period.
+Depletion per unit-of-production (thousand cubic feet of gas equivalent)
+amounted to $2.03, $1.73 and $1.37 for the years ended December 31, 2003, 2002,
+and 2001, respectively.
+Under the full-cost accounting rules of the SEC, the Company reviews the
+carrying value of its proved oil and gas properties each quarter. Under these
+rules, capitalized costs of proved oil and gas properties net of accumulated
+depreciation, depletion and amortization (DD&A) and deferred income taxes, may
+not exceed the present value of estimated future net cash flows from proved oil
+and gas reserves, discounted at 10
+65
+percent, plus the lower of cost or fair value of unproved properties included in
+the costs being amortized, net of related tax effects. These rules generally
+require pricing future oil and gas production at the unescalated market price
+for oil and gas at the end of each fiscal quarter and require a write-down if
+the "ceiling" is exceeded, unless prices recover sufficiently before the date of
+the auditor's report. Given the volatility of oil and gas prices, it is
+reasonably possible that the Company's estimate of discounted future net cash
+flows from proved oil and gas reserves could change in the near term. If oil and
+gas prices decline significantly, even if only for a short period of time, it is
+possible that writedowns of oil and gas properties could occur in the future.
+See Note 13 for information regarding the SEC inquiries concerning the Company's
+proved reserves.
+10. NET PROFITS INTEREST
+From 1989 through 1994, the Constituent Entities entered into separate
+agreements to purchase certain oil and gas properties with gross contract
+acquisition prices of $170,000,000 ($150,000,000 net as of closing dates) and in
+simultaneous transactions, entered into agreements to sell overriding royalty
+interests ("ORRI") in the acquired properties. These ORRI are in the form of net
+profits interests ("NPI") equal to a significant percentage of the excess of
+gross proceeds over production costs, as defined, from the acquired oil and gas
+properties. A net deficit incurred in any month can be carried forward to
+subsequent months until such deficit is fully recovered. The Company has the
+right to abandon the purchased oil and gas properties if it deems the properties
+to be uneconomical.
+The Company has, pursuant to the purchase agreements, created abandonment trusts
+(see Note 7) whereby funds are provided out of gross production proceeds from
+the properties for the estimated amount of future abandonment obligations
+related to the working interests owned by the Company. The Trusts are
+administered by unrelated third party trustees for the benefit of the Company's
+working interest in each property. The Trust agreements limit disbursement of
+funds to the satisfaction of abandonment obligations. Any funds remaining in the
+Trusts after all restoration, dismantlement and abandonment obligations have
+been met will be distributed to the owners of the properties in the same ratio
+as contributions to the Trusts. Estimated future revenues and costs associated
+with the NPI and the Trusts are also excluded from the oil and gas reserve
+disclosures at Note 13. As of December 31, 2003 and 2002, the Trusts' assets
+(all cash and investments) totaled $7,420,000 and $6,896,000 respectively, all
+of which will be available to the Company to pay its portion, as working
+interest owner, of the restoration, dismantlement and abandonment costs
+discussed at Note 7. SFAS 143, discussed in Note 2 and 8, does not allow the
+Abandonment Trusts' assets to be used to offset the associated abandonment
+liability. The Company did not record any income or loss associated with the
+Trust asset or abandonment liability as a result of adoption of SFAS 143.
+At the time of acquisition of properties by the Company, the property owners
+estimated the future costs to be incurred for site restoration, dismantlement
+and abandonment, net of salvage value. A portion of the amounts necessary to pay
+such estimated costs was deposited in the Trusts upon acquisition of the
+properties, and the remainder is deposited from time to time out of the proceeds
+from production. The determination of the amount deposited upon the acquisition
+of the properties and the amount to be deposited as proceeds from production was
+based on numerous factors, including the estimated reserves of the properties.
+As operator, the Company receives all of the revenues and incurs all of the
+production costs for the purchased oil and gas properties but retains only that
+portion applicable to its net ownership share. As a result, the payables and
+receivables associated with operating the properties included in the Company's
+Consolidated Balance Sheets include both the Company's and all other outside
+owners' shares. However,
+66
+revenues and production costs associated with the acquired properties reflected
+in the accompanying Consolidated Statements of Operations represent only the
+Company's share, after reduction for the NPI.
+11. EMPLOYEE BENEFIT PLANS
+The Company has adopted a series of incentive compensation plans designed to
+align the interest of the executives and employees with those of its
+stockholders. The following is a brief description of each plan:
+The Savings and Protection Plan provides employees with the option to
+defer receipt of a portion of their compensation and the Company may, at
+its discretion, match a portion of the employee's deferral with cash and
+Company Common Stock. The Company may also elect, at its discretion, to
+contribute a non-matching amount in cash and Company Common Stock to
+employees. The amounts held under the Savings and Protection Plan are
+invested in various funds maintained by a third party in accordance with
+the directions of each employee. An employee is fully vested, including
+Company discretionary contributions, immediately upon participation in the
+Savings and Protection Plan. The total amounts contributed by the Company,
+including the value of the common stock contributed, were $562,000,
+$611,000 and $595,000 in the years 2003, 2002 and 2001, respectively.
+The 1994 Stock Incentive Plan (the "1994 Plan"), approved by the
+shareholders in 1994, provides for 600,000 shares of Common Stock to be
+reserved for issuance pursuant to such plan. Under the 1994 Plan, the
+Company may grant both stock options qualifying under Section 422 of the
+Internal Revenue Code and options that are not qualified as incentive
+stock options, as well as performance shares. These options have an
+expiration date of 10 years from the date of grant.
+On August 23, 1996, the Board of Directors of the Company approved and
+adopted the Callon Petroleum Company 1996 Stock Incentive Plan (the "1996
+Plan"). The 1996 Plan was approved by the shareholders in 1997 and
+provides for the same types of awards as the 1994 Plan and is limited to a
+maximum of 1,200,000 shares (as amended from the original 900,000 shares)
+of common stock that may be subject to outstanding awards. Unvested
+options are subject to forfeiture upon certain termination of employment
+events and expire 10 years from the date of grant.
+The Company granted 533,000 stock options to employees on March 23, 2000
+and 120,000 stock options to directors on July 25, 2000 at $10.50 per
+share. The March 23, 2000 grant was subject to shareholder approval of an
+amendment to the 1996 Stock Incentive Plan. The amendment, which was
+approved on May 9, 2000 at the Annual Meeting of Shareholders, increased
+the number of shares reserved for issuance under the 1996 plan to
+2,200,000 shares. The excess of the market price over the exercise price
+on the approval date of the amendment is amortized over the three-year
+vesting period of the options. Compensation costs of $27,000, $416,000 and
+$611,000 were recognized in 2003, 2002 and 2001, respectively, related to
+these options.
+On February 14, 2002, the Board of Directors of the Company approved and
+adopted the 2002 Stock Incentive Plan (the "2002 Plan"). Pursuant to the
+2002 Plan, 350,000 shares of common stock shall be reserved for issuance
+upon the exercise of options or for grants of stock options, stock
+appreciation rights or units, bonus stock, or performance shares or units.
+This Plan qualified as a "broadly based" plan under the provisions of the
+New York Stock
+67
+Exchange's rules and regulations and therefore did not require shareholder
+approval. Because the 2002 Plan is a broadly based plan, the aggregate
+number of shares underlying awards granted to officers and directors
+cannot exceed 50% of the total number of shares underlying the awards
+granted to all employees during any three-year period.
+In 2002, the Company awarded 300,000 shares of restricted stock from the
+1996 and the 2002 Plan and 70,500 from treasury shares to be issued as
+vested. The issuance of the restricted stock using treasury shares did not
+require shareholder approval pursuant to the New York Stock Exchange's
+rules and regulations, and therefore shareholder approval was not sought.
+These shares will generally vest to the recipients over a three-year
+period (one-third in each year) beginning in November 2002. The deferred
+compensation portion of this grant will be amortized to expense over the
+vesting period. The non-cash amortization expense in, 2003 and 2002 was
+$454,000 and $496,000, respectively.
+In 1997, the Board of Directors authorized the implementation of the
+Callon Petroleum Company 1997 Employee Stock Purchase Plan (the "1997
+Purchase Plan"), which was approved by the Company's shareholders at the
+1997 Annual Meeting. The Plan provides eligible employees of the Company
+with the opportunity to acquire a proprietary interest in the Company
+through participation in a payroll deduction-based employee stock purchase
+plan. An aggregate of 250,000 shares of common stock have been reserved
+for issuance over the 10-year term of the 1997 Purchase Plan. The purchase
+price per share at which common stock will be purchased on the
+participant's behalf on each purchase date within an offering period is
+equal to 85 percent of the fair market value per share of common stock.
+A summary of the status of the Company's stock option plans for the three most
+recent years and changes during the years then ended is presented in the table
+and narrative below:
+2003 2002 2001
+--------------------- ---------------------- ----------------------
+WTD AVG WTD AVG WTD AVG
+SHARES EX PRICE SHARES EX PRICE SHARES EX PRICE
+---------- -------- ---------- --------- ---------- --------
+Outstanding, beginning of year 2,520,417 $ 9.90 2,332,667 $ 10.84 2,304,167 $ 10.83
+Granted (at market) 30,000 5.12 310,000 4.45 30,000 11.61
+Exercised (500) 4.10 -- -- (1,500) 9.00
+Forfeited (99,050) 9.74 (122,250) 14.10 -- --
+Expired -- -- -- -- -- --
+---------- -------- ---------- ------- ---------- -------
+Outstanding, end of year 2,450,867 $ 9.84 2,520,417 $ 9.90 2,332,667 $ 10.84
+========== ======== ========== ======= ========== =======
+Exercisable, end of year 2,262,067 $ 10.31 2,224,334 $ 10.57 2,057,977 $ 10.80
+========== ======== ========== ======= ========== =======
+Weighted average fair value of
+options granted (at market) $ 2.97 $ 2.44 $ 5.80
+========== ========== ==========
+68
+The following table sets forth additional information regarding options
+outstanding at December 31, 2003. Contractual life and exercise prices represent
+weighted averages for options outstanding and options exercisable.
+Options Outstanding Options Exercisable
+------------------------------------- ----------------------
+Range of Number Contractual Exercise Number Exercise
+exercise prices Outstanding Life (years) Price Exercisable Price
+------------------ ----------- ------------ -------- ----------- --------
+$ 3.70 to $ 6.41 315,200 8.6 $ 4.47 126,400 $ 4.74
+$ 9.00 to $ 12.28 2,070,667 3.9 $ 10.53 2,070,667 $ 10.53
+$ 13.56 to $ 15.31 65,000 4.3 $ 14.16 65,000 $ 14.16
+The fair value of each option grant is estimated on the date of grant using the
+Black-Scholes option pricing model with the following weighted average
+assumptions used for options granted during the years presented are as follows:
+2003 2002 2001
+------ ------ ------
+Risk free interest rate 4.0% 3.7% 4.5%
+Expected life (years) 5.0 5.0 5.0
+Expected volatility 65.3% 61.0% 43.9%
+Expected dividends -- -- --
+12. EQUITY TRANSACTIONS
+In November 1995, the Company sold 1,315,500 shares of $2.125 Convertible
+Exchangeable Preferred Stock, Series A (the "Preferred Stock") for net proceeds
+of $30.9 million. Annual dividends are $2.125 per share and are cumulative. The
+net proceeds of the $.01 par value stock after underwriters discount and expense
+was $30,899,000. Each share has a liquidation preference of $25.00, plus accrued
+and unpaid dividends. Dividends on the Preferred Stock are cumulative from the
+date of issuance and are payable quarterly, commencing January 15, 1996. The
+Preferred Stock is convertible at any time, at the option of the holders
+thereof, unless previously redeemed, into shares of Common Stock of the Company
+at an initial conversion price of $11 per share of Common Stock, subject to
+adjustments under certain conditions.
+The Preferred Stock is redeemable at any time on or after December 31, 1998, in
+whole or in part at the option of the Company at a redemption price of $26.488
+per share beginning at December 31, 1998 and at premiums declining to the $25.00
+liquidation preference by the year 2005 and thereafter, plus accrued and unpaid
+dividends. The Preferred Stock is also exchangeable, in whole, but not in part,
+at the option of the Company on or after January 15, 1998 for the Company's 8.5%
+Convertible Subordinated Debentures due 2010 (the "Debentures") at a rate of
+$25.00 principal amount of Debentures for each share of Preferred Stock. The
+Debentures will be convertible into Common Stock of the Company on the same
+terms as the Preferred Stock and will pay interest semi-annually.
+In a December 1998 private transaction, a preferred stockholder elected to
+convert 59,689 shares of Preferred Stock into 136,867 shares of the Company's
+Common Stock. In 1999 certain other preferred stockholders, through private
+transactions, agreed to convert 210,350 shares of Preferred Stock into 502,637
+shares of the Company's Common Stock under similar terms. Likewise in 2000,
+444,600 shares of Preferred Stock were
+69
+converted into 1,036,098 shares of the Company's Common Stock. Any non-cash
+premium negotiated in excess of the conversion rate was recorded as additional
+preferred stock dividends and excluded from the Consolidated Statements of Cash
+Flows.
+The Company adopted a stockholder rights plan on March 30, 2000, designed to
+assure that the Company's stockholders receive fair and equal treatment in the
+event of any proposed takeover of the Company and to guard against partial
+tender offers, squeeze-outs, open market accumulations, and other abusive
+tactics to gain control without paying all stockholders a fair price. The rights
+plan was not adopted in response to any specific takeover proposal. Under the
+rights plan, the Company declared a dividend of one right ("Right") on each
+share of the Company's Common Stock. Each Right will entitle the holder to
+purchase one one-thousandth of a share of a Series B Preferred Stock, par value
+$0.01 per share, at an exercise price of $90 per one one-thousandth of a share.
+The Rights are not currently exercisable and will become exercisable only in the
+event a person or group acquires, or engages in a tender or exchange offer to
+acquire, beneficial ownership of 15 percent or more (one existing stockholder
+was granted an exception for up to 21 percent) of the Company's Common Stock.
+After the Rights become exercisable, each Right will also entitle its holder to
+purchase a number of common shares of the Company having a market value of twice
+the exercise price. The dividend distribution was made to stockholders of record
+at the close of business on April 10, 2000. The Rights will expire on March 30,
+2010.
+13. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)
+The Company's proved oil and gas reserves at December 31, 2003, 2002 and 2001
+have been estimated by independent petroleum consultants in accordance with
+guidelines established by the Securities and Exchange Commission ("SEC").
+Accordingly, the following reserve estimates are based upon existing economic
+and operating conditions. These estimates have been adjusted (per SEC
+guidelines) to exclude the volumetric production payment described in Note 2.
+There are numerous uncertainties inherent in establishing quantities of proved
+reserves. The following reserve data represents estimates only and should not be
+construed as being exact. In addition, the standard measure of discounted future
+net cash flows should not be construed as the current market value of the
+Company's oil and gas properties or the cost that would be incurred to obtain
+equivalent reserves. Reference the discussion in Note 7 regarding the Deep Water
+Royalty Relief Act and the potential loss of reserves.
+Beginning in October 2002, the Company received a series of inquiries from the
+SEC regarding its Annual Report on Form 10-K for the year ended December 31,
+2001 requesting supplemental information concerning its operations in the Gulf
+of Mexico. The comment letters requested information about the procedures the
+Company used to classify its deepwater reserves as proved and requested that the
+Company's financials be restated to reflect the removal of the Boomslang
+reserves as proved for all prior periods during which such reserves were
+reported as proved. The Company has reviewed the SEC comments with its
+independent petroleum reserve engineers, Huddleston & Co., Inc. of Houston,
+Texas. Both Huddleston & Co. and Callon believe that such deepwater reserves are
+properly classified as proved. If the SEC requires the Company to retroactively
+classify Boomslang as an unproved property through December, 2002, the Company
+would be required to restate its financial position, results of operations, and
+supplemental oil and gas reserve data from 1999 through 2003. The Company has
+responded to all of the SEC inquiries.
+70
+ESTIMATED RESERVES
+Changes in the estimated net quantities of crude oil and natural gas reserves,
+all of which are located onshore and offshore in the continental United States,
+are as follows:
+RESERVE QUANTITIES
+YEARS ENDED DECEMBER 31,
+------------------------
+2003 2002 2001
+---- ---- ----
+Proved developed and undeveloped reserves:
+Crude Oil (MBbls):
+Beginning of period 24,043 30,209 33,382
+Revisions to previous estimates (1) (8,699) (a) (2,290)
+Purchase of reserves in place -- -- --
+Sales of reserves in place (65) -- (624)
+Extensions and discoveries -- 2,759 (a) 14
+Production (268) (226) (273)
+------- ------- -------
+End of period 23,709 24,043 30,209
+======= ======= =======
+Natural Gas (MMcf):
+Beginning of period 91,539 120,299 129,922
+Revisions to previous estimates (6,407) (19,284) (a) (4,578)
+Purchase of reserves in place -- -- --
+Sales of reserves in place (49) -- (1,296)
+Extensions and discoveries 1,923 3,584 (a) 7,483
+Production (12,315) (13,060) (11,232)
+------- ------- -------
+End of period 74,691 91,539 120,299
+======= ======= =======
+Proved developed reserves:
+Crude Oil (MBbls):
+Beginning of period 1,056 885 2,192
+======= ======= =======
+End of period 9,919 1,056 885
+======= ======= =======
+Natural Gas (MMcf):
+Beginning of period 37,631 51,221 63,982
+======= ======= =======
+End of period 31,415 37,631 51,221
+======= ======= =======
+(a) For the year ended December 31, 2002, revisions to previous estimates and
+extensions and discoveries were adjusted from the amounts reported in the
+Company's Annual Report on Form 10-K dated March 27, 2003 to reflect the
+subsequent changes in properties that were part of property acquisitions or
+exploratory drilling programs and should have been classified as extensions
+instead of revisions.
+71
+STANDARDIZED MEASURE
+The following tables present the Company's standardized measure of discounted
+future net cash flows and changes therein relating to proved oil and gas
+reserves and were computed using reserve valuations based on regulations
+prescribed by the SEC. These regulations provide that the oil, condensate and
+gas price structure utilized to project future net cash flows reflects current
+prices (approximately $5.99 per Mcf for natural gas and $30.50 per Bbl for oil
+for the 2003 disclosures, $4.80 per Mcf and $34.22 per Bbl for 2002 disclosures,
+and $2.58 per Mcf and $20.10 per Bbl for 2001 disclosures) at each date
+presented and have not been escalated. Future production, development and net
+abandonment costs are based on current costs without escalation. The resulting
+net future cash flows have been discounted to their present values based on a
+10% annual discount factor.
+STANDARDIZED MEASURE
+YEARS ENDED DECEMBER 31,
+--------------------------------------
+2003 2002 2001
+----------- ----------- ----------
+(IN THOUSANDS)
+Future cash inflows $ 1,170,118 $ 1,261,571 $ 883,145
+Future costs -
+Production (219,421) (165,559) (220,857)
+Development and net abandonment (111,850) (125,813) (191,369)
+----------- ----------- ----------
+Future net inflows before income taxes 838,847 970,199 470,919
+Future income taxes (89,567) (119,020) (30,315)
+----------- ----------- ----------
+Future net cash flows 749,280 851,179 440,604
+10% discount factor (230,254) (295,133) (185,747)
+----------- ----------- ----------
+Standardized measure of discounted
+future net cash flows $ 519,026 $ 556,046 $ 254,857
+=========== =========== ==========
+CHANGES IN STANDARDIZED MEASURE
+YEARS ENDED DECEMBER 31,
+----------------------------------
+2003 2002 2001
+---------- --------- ---------
+(IN THOUSANDS)
+Standardized measure - beginning of period $ 556,046 $ 254,857 $ 671,197
+Sales and transfers, net of production costs (62,396) (38,375) (45,672)
+Net change in sales and transfer prices,
+net of production costs (41,011) 401,837 (604,391)
+Exchange and sale of in place reserves (1,226) -- (5,850)
+Purchases, extensions, discoveries, and improved
+recovery, net of future production and
+development costs incurred 25,632 8,456 9,358
+Revisions of quantity estimates (18,018) (103,452) (23,314)
+Accretion of discount 62,394 26,915 90,978
+Net change in income taxes 16,460 (53,608) 224,290
+Changes in production rates, timing and other (18,855) 59,416 (61,739)
+--------- --------- ---------
+Standardized measure - end of period $ 519,026 $ 556,046 $ 254,857
+========= ========= =========
+72
+14. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
+FIRST SECOND THIRD FOURTH
+QUARTER QUARTER QUARTER QUARTER
+-----------------------------------------
+(IN THOUSANDS, EXCEPT PER SHARE DATA)
+2003
+Total revenues $ 21,351 $ 18,482 $ 15,152 $ 19,156
+Total costs and expenses 19,503 19,477 18,270 26,623
+Income tax expense (benefit) 647 (348) (1,092) 9,225
+Income (loss) before cumulative effect of change
+in accounting principle 1,201 (647) (2,026) (16,700)
+Net income (loss) 1,382 (647) (2,026) (16,700)
+Net income (loss) per common share-basic:
+Net income (loss) available to common before
+cumulative effect of change in accounting principle $ 0.07 ($0.07) ($0.17) ($1.24)
+Cumulative effect of change in accounting principle,
+net of tax 0.01 0.00 0.00 0.00
+-------- ------- ------- -------
+Net income (loss) per share $ 0.08 ($0.07) ($0.17) ($1.24)
+Net income (loss) per common share-diluted:
+Net income (loss) available to common before
+cumulative effect of change in accounting principle $ 0.07 ($0.07) ($0.17) ($1.24)
+Cumulative effect of change in accounting principle,
+net of tax 0.01 0.00 0.00 0.00
+-------- ------- ------- -------
+Net income (loss) per share $ 0.08 ($0.07) (0.17) (1.24)
+2002
+Total revenues $ 11,624 $ 20,489 $ 15,786 $ 19,209
+Total costs and expenses 15,399 16,888 17,786 19,606
+Income tax expense (benefit) (1,321) 1,260 (700) (139)
+Net income (loss) (2,454) 2,341 (1,300) (258)
+Net income (loss) per share-basic (0.21) 0.15 (0.12) (0.04)
+Net income (loss) per share-diluted (0.21) 0.15 (0.12) (0.04)
+73
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
+FINANCIAL DISCLOSURE
+There have been no disagreements with the independent auditors on any matters of
+accounting principles or practices, financial statement disclosure, or auditing
+scope or procedures.
+ITEM 9A. CONTROLS AND PROCEDURES
+The term "disclosure controls and procedures" is defined in Rules 13a-15(e) and
+15d-15(e) of the Securities Exchange Act of 1934, or the Exchange Act. This term
+refers to the controls and procedures of a company that are designed to ensure
+that information required to be disclosed by a company in the reports that it
+files or submits under the Exchange Act is recorded, processed, summarized and
+reported within the time periods specified by the Securities and Exchange
+Commission. Our management, including our Chief Executive Officer and Chief
+Financial Officer, has evaluated the effectiveness of our disclosure controls
+and procedures as of the end of the period covered by this annual report. Based
+upon that evaluation, our Chief Executive Officer and Chief Financial Officer
+have concluded that our disclosure controls and procedures were effective as of
+the end of the period covered by this annual report.
+There were no changes to our internal control over financial reporting during
+our last fiscal quarter that has materially affected, or is reasonably likely to
+materially affect, our internal control over financial reporting.
+74
+PART III.
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
+For information concerning Item 10, see the definitive proxy statement of Callon
+Petroleum Company relating to the Annual Meeting of Stockholders on May 6, 2004
+which will be filed with the Securities and Exchange Commission and is
+incorporated herein by reference.
+ITEM 11. EXECUTIVE COMPENSATION.
+For information concerning Item 11, see the definitive proxy statement of Callon
+Petroleum Company relating to the Annual Meeting of Stockholders on May 6, 2004
+which will be filed with the Securities and Exchange Commission and is
+incorporated herein by reference.
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
+RELATED STOCKHOLDER MATTERS.
+For information concerning the security ownership of certain beneficial owners
+and management, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 6, 2004 which will be
+filed with the Securities and Exchange Commission and is incorporated herein by
+reference.
+EQUITY COMPENSATION PLAN INFORMATION
+The following table provides information as of December 31, 2003 regarding the
+number of shares of Common Stock that may be issued under the Company's equity
+compensation plans.
+Plan Category Number of securities to be Weighted-average Number of securities
+issued upon exercise of exercise price of remaining available for
+outstanding options, outstanding options, future issuance under
+warrants and rights warrants and rights equity compensation
+plans (excluding
+securities reflected
+in column (a)
+(A) (B) (C)
+--- --- ---
+Equity compensation
+plans approved by
+security holders(1) 2,264,667 $10.30 197,140
+Equity compensation
+plans not approved by
+security holders (2) 186,200 $ 4.33 75,317
+--------- ------ -------
+Total 2,450,867 $ 9.84 272,457
+========= ====== =======
+(1) Represents the Callon Petroleum Company 1994 and the 1996 Stock
+Incentive Plans which were approved by the shareholders in prior
+years. Remaining shares available for future
+75
+issuance listed in column (c) does not include 56,000 shares of
+restricted stock awarded in 2002 which have not yet vested.
+(2) Represents the Callon Petroleum Company 2002 Stock Incentive Plan
+adopted by the Company on February 14, 2002. The plan qualified as a
+"broadly based" plan under the provisions of the New York Stock
+Exchange rules and regulations and therefore did not require
+shareholder approval. Remaining shares available for future issuance
+listed in column (c) does not include 34,484 shares of restricted
+stock awarded in 2002 which have not yet vested.
+See Note 10 to the Consolidated Financial Statements for a description of the
+material provisions of each equity compensation plan under which our equity
+securities are authorized for issuance that was adopted without the approval of
+shareholders.
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
+For information concerning Item 13, see the definitive proxy statement of Callon
+Petroleum Company relating to the Annual Meeting of Stockholders on May 6, 2004
+which will be filed with the Securities and Exchange Commission and is
+incorporated herein by reference.
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
+For information concerning Item 14, see the definitive proxy statement of Callon
+Petroleum Company relating to the Annual Meeting of Stockholders on May 6, 2004
+which will be filed with the Securities and Exchange Commission and is
+incorporated herein by reference.
+76
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index 0000000000000000000000000000000000000000..2c4df22049fa40e4e4e3321d266706278afb76c0
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+++ b/raw/filings/0000928022/2003/0000950134-04-003498/item13.txt
@@ -0,0 +1,5 @@
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
+For information concerning Item 13, see the definitive proxy statement of Callon
+Petroleum Company relating to the Annual Meeting of Stockholders on May 6, 2004
+which will be filed with the Securities and Exchange Commission and is
+incorporated herein by reference.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2003/0000950134-04-003498/item9a.txt b/raw/filings/0000928022/2003/0000950134-04-003498/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..3e4e63ab64cb14ac189b1768c5ee7e5913cda655
--- /dev/null
+++ b/raw/filings/0000928022/2003/0000950134-04-003498/item9a.txt
@@ -0,0 +1,18 @@
+ITEM 9A. CONTROLS AND PROCEDURES
+The term "disclosure controls and procedures" is defined in Rules 13a-15(e) and
+15d-15(e) of the Securities Exchange Act of 1934, or the Exchange Act. This term
+refers to the controls and procedures of a company that are designed to ensure
+that information required to be disclosed by a company in the reports that it
+files or submits under the Exchange Act is recorded, processed, summarized and
+reported within the time periods specified by the Securities and Exchange
+Commission. Our management, including our Chief Executive Officer and Chief
+Financial Officer, has evaluated the effectiveness of our disclosure controls
+and procedures as of the end of the period covered by this annual report. Based
+upon that evaluation, our Chief Executive Officer and Chief Financial Officer
+have concluded that our disclosure controls and procedures were effective as of
+the end of the period covered by this annual report.
+There were no changes to our internal control over financial reporting during
+our last fiscal quarter that has materially affected, or is reasonably likely to
+materially affect, our internal control over financial reporting.
+74
+PART III.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2003/0000950134-04-003498/rp_note.txt b/raw/filings/0000928022/2003/0000950134-04-003498/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2003/0000950134-04-003498/rpt_disclosure.txt b/raw/filings/0000928022/2003/0000950134-04-003498/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..278b81ffeaf272561b74300a8656fbfece88b968
--- /dev/null
+++ b/raw/filings/0000928022/2003/0000950134-04-003498/rpt_disclosure.txt
@@ -0,0 +1,59 @@
+Related Party Transactions Oversight . The Company shall not enter
+into a related party transaction unless such transaction is approved by
+the Committee after a review of the transaction by the Committee for
+potential conflicts of interest. A transaction will be considered a
+“related party transaction” if the transaction would be required to be
+disclosed under Item 404 of Regulation S-K. 
+9. 
+Risk Management Oversight . 
+9.1. 
+Risk Exposure . The Committee shall periodically meet with
+management and each Independent Auditor to review and discuss (a)
+guidelines and policies with respect to risk assessment and risk
+management to the extent necessary or appropriate to govern the process
+by which the Company’s risk assessment and management is undertaken and
+handled (although the Committee is not required to be the sole body
+responsible for risk assessment and management) and (b) the Company’s
+major financial risk exposures and the steps management has taken to
+monitor and control such exposures. If the Company manages and
+assesses its risk through mechanisms other than the Committee, the
+mechanisms need not be replaced by the Committee, but the processes in
+place should be reviewed in a general manner by the Committee. 
+9.2. 
+Insurance . The Committee shall periodically review and assess
+insurance coverage, including Directors and Officers Liability,
+property and casualty loss, errors and omissions and surety bonds, with
+management and, at the Committee’s discretion, General Counsel. 
+9.3. 
+Special-Purpose Entities and Off-Balance Sheet Transactions . The
+Committee shall periodically meet with management, the Internal
+Auditor, the General Counsel and the External Auditor to review and
+assess all “special-purpose” entities of the Company and all complex
+financing transactions involving the Company, including all related
+off-balance sheet accounting matters. 
+9.4. 
+Consultation with Legal Counsel . The Committee shall periodically,
+at its discretion, review with the General Counsel and, if the
+Committee deems it appropriate, outside legal counsel legal matters
+(including material claims, pending legal proceedings, government
+investigations and material reports, notices or inquires received from
+governmental agencies) that may have a significant impact on the
+Company’s financial statements or risk management. 
+10. 
+Reports and Assessments . 
+10.1. 
+Board Reports . The Chairperson of the Committee shall,
+periodically, at his or her discretion, report to the Board on
+Committee actions and on the fulfillment of the Committee’s
+responsibilities under this Charter. Such reports shall include any
+issues that arise with respect to the quality or integrity of the
+Company’s financial statements, the Company’s compliance with legal or
+regulatory requirements, the performance and independence of the
+Company’s External Auditors and the performance of the Company’s
+internal audit function. This report shall be presented and
+incorporated with and into the next regularly scheduled Board meeting. 
+29
+Table of Contents 
+10.2. 
+Charter Assessment . The Committee shall annually assess the
+adequacy of this Charter and advise the Board and the Nominating and
\ No newline at end of file
diff --git a/raw/filings/0000928022/2004/0000950134-05-004630/filing.txt b/raw/filings/0000928022/2004/0000950134-05-004630/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..78f33ef4c998ede75ecc198769ac24f740d6ca3e
--- /dev/null
+++ b/raw/filings/0000928022/2004/0000950134-05-004630/filing.txt
@@ -0,0 +1,6952 @@
+10-K
+1
+d23168e10vk.htm
+FORM 10-K
+e10vk 
+Table of Contents 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF 
+THE SECURITIES EXCHANGE ACT OF 1934 
+FOR THE FISCAL YEAR ENDED DECEMBER 31, 2004 
+Commission File Number 001-14039 
+CALLON PETROLEUM COMPANY 
+(Exact name of Registrant as specified in its charter) 
+Delaware 
+64-0844345 
+(State or other jurisdiction of
+(I.R.S. Employer 
+incorporation or organization)
+Identification No.) 
+200 North Canal Street 
+Natchez, Mississippi 39120 
+(601) 442-1601 
+(Address of Principal Executive
+(Registrant’s telephone number 
+Offices)(Zip Code)
+including area code) 
+Securities registered pursuant to Section 12(b) of the Act:
+Title of each class 
+Name of exchange on which registered 
+Convertible Exchangeable Preferred Stock,
+New York Stock Exchange 
+Series A, Par Value $.01 Per Share 
+Common Stock, Par Value $.01 Per Share
+New York Stock Exchange 
+Preferred Stock Purchase Rights
+New York Stock Exchange 
+Securities registered pursuant to Section 12(g) of the Act: None 
+Indicate by check mark whether the Registrant (1) has filed all reports required to be filed
+by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
+for such shorter period that the Registrant was required to file such reports), and (2) has been
+subject to such filing requirements for the past 90 days. Yes þ . No. o .
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
+not contained herein, and will not be contained, to the best of Registrant’s knowledge, in
+definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
+or any amendment to this Form 10-K.
+Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act
+Rule 12b-2). Yes þ . No. o .
+The aggregate market value of the voting and non-voting common equity held by nonaffiliates of the
+registrant was approximately $212.9 million as of June 30, 2004 (based on the last reported sale
+price of such stock on the New York Stock Exchange on such date of $14.26).
+As of March 3, 2005, there were 17,720,866 shares of the Registrant’s Common Stock, par value $.01
+per share, outstanding.
+Document incorporated by reference: Portions of the definitive Proxy Statement of Callon Petroleum
+Company (to be filed no later than 120 days after December 31, 2004) relating to the Annual Meeting
+of Stockholders to be held on May 5, 2005 which is incorporated into Part III of this Form 10-K.
+1
+TABLE OF CONTENTS 
+PART I. 
+ITEM 1 and 2. BUSINESS and PROPERTIES 
+ITEM 3. LEGAL PROCEEDINGS 
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 
+PART II. 
+ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS 
+ITEM 6. SELECTED FINANCIAL DATA 
+ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS 
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+ITEM 9.A CONTROLS AND PROCEDURES 
+ITEM 9.B OTHER INFORMATION 
+PART III 
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 
+ITEM 11. EXECUTIVE COMPENSATION 
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+PART IV 
+ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 
+SIGNATURES 
+EXHIBIT INDEX 
+Consent of Ernst & Young LLP 
+Consent of Huddleston & Co., Inc. 
+Certification of CEO Pursuant to Rule 13(a)-14(a) 
+Certification of CFO Pursuant to Rule 13(a)-14(a) 
+Certification of CEO Pursuant to Rule 13(a)-14(b) 
+Certification of CFO Pursuant to Rule 13(a)-14(b) 
+Table of Contents 
+PART I. 
+ITEM 1 and 2. BUSINESS and PROPERTIES 
+Overview 
+Callon Petroleum Company has been engaged in the exploration, development, acquisition and
+production of oil and gas properties since 1950. Our properties are geographically
+concentrated primarily offshore in the Gulf of Mexico and onshore in Louisiana and Alabama. We
+were incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of
+a publicly traded limited partnership, a joint venture with a consortium of European investors and
+an independent energy company owned by members of current management. As used herein, the
+“Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors
+and subsidiaries unless the context requires otherwise.
+In 1989, we began increasing our reserves through the acquisition of producing properties that were
+geologically complex, had (or were analogous to fields with) an established production history from
+stacked pay zones and were candidates for exploitation. We focused on reducing operating costs and
+implementing production enhancements through the application of technologically advanced production
+and recompletion techniques.
+Over the past nine years, we have also placed emphasis on the acquisition of acreage with
+exploration and development drilling opportunities in the Gulf of Mexico shelf and deepwater areas.
+At December 31, 2004, we owned working interests in a total of 72 blocks/leases covering 145,000
+net acres. To minimize risk we join with industry partners to explore federal offshore blocks
+acquired in the Gulf of Mexico. We perform extensive geological and geophysical studies using
+computer-aided exploration techniques (CAEX), including, where appropriate, the acquisition of 3-D
+seismic or high-resolution 2-D data to facilitate these efforts. We continue to develop prospects
+on the shelf through our 3-D seismic partnership using Amplitude versus Offset (“AVO”) technology.
+In 1998, we began exploration in the Gulf of Mexico deepwater area (generally 900 to 5,500 feet of
+water) and during the fourth quarter of 2003, our first two deepwater projects, the Medusa and
+Habanero fields, began production. Please see “Significant Properties” for a more detailed
+discussion.
+We ended the year 2004 with estimated net proved reserves of 191 billion cubic feet of natural gas
+equivalent (“Bcfe”). This represents a decrease of 12% from 2003 year-end estimated net proved
+reserves of 217 Bcfe.
+The major focus of our future operations is expected to continue to be the exploration for and
+development of oil and gas properties, primarily in the Gulf of Mexico.
+Availability of Reports 
+All of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
+8-K, and amendments to such reports as well as other filings we make pursuant to Section 13(a) and
+15(d) of the Securities Exchange Act of 1934 are available free of charge on our Internet website.
+The address of our Internet website is www.callon.com. Our Securities and Exchange Commission
+(“SEC”) filings are available on our website as soon as they are posted to the EDGAR database on
+the SEC’s website.
+2
+Table of Contents 
+Business Strategy 
+Our goal is to increase shareholder value by increasing our reserves, production, cash flow and
+earnings. We seek to achieve these goals through the following strategies:
+• 
+focus on Gulf of Mexico exploration with a balance between shelf and deepwater areas
+using the latest available technology; 
+• 
+aggressively explore our existing prospect inventory; and 
+• 
+replenish our prospect inventory with increasing emphasis on prospect generation using
+AVO technology. 
+Exploration and Development Activities 
+Capital expenditures for exploration and development costs related to oil and gas properties
+totaled approximately $65 million in 2004. We incurred approximately $19 million in the Gulf of
+Mexico deepwater area primarily for continued development costs at our Habanero and Medusa
+discoveries and drilling of two satellite wells in the Medusa area. Interest of approximately $5
+million and general and administrative costs allocable directly to exploration and development
+projects of $7 million were capitalized in 2004. Our Gulf of Mexico shelf area expenditures account
+for the remainder of the total capital expended, which includes the developmental drilling and
+completion of a shallow miocene well and a shelf well and the drilling of six exploratory shelf
+wells, one of which was completed in 2004. Two are scheduled for completion during early 2005.
+Risk Factors 
+A decrease in oil and gas prices may adversely affect our results of operations and financial
+condition . Our success is highly dependent on prices for oil and gas, which are extremely volatile.
+Any substantial or extended decline in the price of oil or gas would have a material adverse effect
+on us. Oil and gas markets are both seasonal and cyclical. The prices of oil and gas depend on
+factors we cannot control such as weather, economic conditions, and levels of production, actions
+by OPEC and other countries and government actions. Prices of oil and gas will affect the following
+aspects of our business:
+• 
+our revenues, cash flows and earnings; 
+• 
+the amount of oil and gas that we are economically able to produce; 
+• 
+our ability to attract capital to finance our operations and the cost of the capital; 
+• 
+the amount we are allowed to borrow under our senior secured credit facility; 
+• 
+the value of our oil and gas properties; and 
+• 
+the profit or loss we incur in exploring for and developing our reserves. 
+3
+Table of Contents 
+Our reserve information represents estimates that may turn out to be incorrect if the assumptions
+upon which these estimates are based are inaccurate. Any material inaccuracies in these reserve
+estimates or underlying assumptions will materially affect the quantities and present value of our
+reserves. The process of estimating oil and gas reserves is complex. It requires interpretations
+of available technical data and various assumptions, including assumptions relating to economic
+factors. Any significant inaccuracies in these interpretations or assumptions could materially
+affect the estimated quantities and present value of reserves shown in this annual report.
+In order to prepare these estimates, we must project production rates and the timing of development
+expenditures. The assumptions regarding the timing and costs to commence production from our
+deepwater wells used in preparing our reserves are often subject to revisions over time as
+described under “Our deepwater operations have special operational risks that may negatively affect
+the value of those assets.” We must also analyze available geological, geophysical, production and
+engineering data, the extent, quality and reliability of which can vary. The process also requires
+us to make economic assumptions, such as oil and gas prices, drilling and operating expenses,
+capital expenditures, taxes and availability of funds. Therefore, estimates of oil and gas
+reserves are inherently imprecise.
+Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating
+expenses and quantities of recoverable oil and gas reserves most likely will vary from our
+estimates. Any significant variance could materially affect the estimated quantities and present
+value of reserves shown in this report. In addition, we may adjust estimates of proved reserves to
+reflect production history, results of exploration and development, prevailing oil and gas prices
+and other factors, many of which are beyond our control.
+You should not assume that the present value of future net cash flows from our proved reserves
+referred to in this report is the current market value of our estimated oil and gas reserves. In
+accordance with SEC requirements, we generally base the estimated discounted future net cash flows
+from our proved reserves on prices and costs on the date of the estimate. Actual future prices and
+costs may differ materially from those used in the present value estimate.
+Information about reserves constitutes forward-looking information. See “Forward-Looking
+Statements” for information regarding forward-looking information. The discounted present value of
+our oil and gas reserves is prepared in accordance with guidelines established by the SEC. A
+purchaser of reserves would use numerous other factors to value our reserves. The discounted
+present value of reserves, therefore, does not represent the fair market value of those reserves.
+On December 31, 2004, approximately 44% of the discounted present value of our estimated net proved
+reserves were proved undeveloped. Proved undeveloped reserves represented 50% of total proved
+reserves. Substantially all of these proved undeveloped reserves were attributable to our deepwater
+properties. Development of these properties is subject to additional risks as described above.
+Unless we are able to replace reserves which we have produced, our cash flows and production will
+decrease over time. Our future success depends upon our ability to find, develop and acquire oil
+and gas reserves that are economically recoverable. As is generally the case for Gulf properties,
+our producing properties usually have high initial production rates, followed by a steep decline in
+production. As a result, we must continually locate and develop or acquire new oil and gas reserves
+to replace those being depleted by production. We must do this even during periods of low oil and
+gas prices when it is difficult to raise the capital necessary to finance these activities and
+during periods of high operating costs when it
+4
+Table of Contents 
+is expensive to contract for drilling rigs and other
+equipment and personnel necessary to explore for oil
+and gas. Without successful exploration or acquisition activities, our reserves, production and
+revenues will decline rapidly. We cannot assure you that we will be able to find and develop or
+acquire additional reserves at an acceptable cost.
+A significant part of the value of our production and reserves is concentrated in a small number of
+offshore properties, and any production problems or inaccuracies in reserve estimates related to
+those properties would adversely impact our business. During 2004, 83% of our daily production
+came from four of our properties in the Gulf of Mexico. Moreover, one property accounted for 34% of
+our production during this period. In addition, at December 31, 2004, most of our proved reserves
+were located in three fields in the Gulf of Mexico, with approximately 82% of our total net proved
+reserves attributable to these properties. If mechanical problems, storms or other events
+curtailed a substantial portion of this production or if the actual reserves associated with any
+one of these producing properties are less than our estimated reserves, our results of operations
+and financial condition could be adversely affected.
+Our focus on exploration projects increases the risks inherent in our oil and gas activities. Our
+business strategy focuses on replacing reserves through exploration, where the risks are greater
+than in acquisitions and development drilling. Although we have been successful in exploration in
+the past, we cannot assure you that we will continue to increase reserves through exploration or at
+an acceptable cost. Additionally, we are often uncertain as to the future costs and timing of
+drilling, completing and producing wells. Our drilling operations may be curtailed, delayed or
+canceled as a result of a variety of factors, including:
+• 
+unexpected drilling conditions; 
+• 
+pressure or inequalities in formations; 
+• 
+equipment failures or accidents; 
+• 
+adverse weather conditions; 
+• 
+compliance with governmental requirements; and 
+• 
+shortages or delays in the availability of drilling rigs and the delivery of equipment. 
+We do not operate all of our properties and have limited influence over the operations of some of
+these properties, particularly our deepwater properties. Our lack of control could result in the
+following:
+• 
+the operator may initiate exploration or development on a faster or slower pace than we
+prefer; 
+• 
+the operator may propose to drill more wells or build more facilities on a project than
+we have funds for or that we deem appropriate, which may mean that we are unable to
+participate in the project or share in the revenues generated by the project even though we
+paid our share of exploration costs; and 
+• 
+if an operator refuses to initiate a project, we may be unable to pursue the project. 
+Any of these events could materially reduce the value of our properties.
+Our deepwater operations have special operational risks that may negatively affect the value of
+those assets. Drilling operations in the deepwater area are by their nature more difficult and
+costly than drilling operations in shallow water. Deepwater drilling operations require the
+application of more advanced drilling technologies involving a higher risk of technological failure
+and usually have significantly higher drilling costs than shallow water drilling operations.
+Deepwater wells are completed
+5
+Table of Contents 
+using sub-sea completion techniques that require substantial time and
+the use of advanced remote installation equipment. These operations involve a high risk of mechanical difficulties and
+equipment failures that could result in significant cost overruns.
+In deepwater, the time required to commence production following a discovery is much longer than in
+shallow water and on-shore. Deepwater discoveries require the construction of expensive production
+facilities and pipelines prior to production. We cannot estimate the costs and timing of the
+construction of these facilities with certainty, and the accuracy of our estimates will be affected
+by a number of factors beyond our control, including the following:
+• 
+decisions made by the operators of our deepwater wells; 
+• 
+the availability of materials necessary to construct the facilities; 
+• 
+the proximity of our discoveries to pipelines; and 
+• 
+the price of oil and natural gas. 
+Delays and cost overruns in the commencement of production will affect the value of our deepwater
+prospects and the discounted present value of reserves attributable to those prospects.
+Competitive industry conditions may negatively affect our ability to conduct operations. We
+operate in the highly competitive areas of oil and gas exploration, development and production. We
+compete for the purchase of leases in the Gulf of Mexico from the U. S. government and from other
+oil and gas companies. These leases include exploration prospects as well as properties with
+proved reserves. Factors that affect our ability to compete in the marketplace include:
+• 
+our access to the capital necessary to drill wells and acquire properties; 
+• 
+our ability to acquire and analyze seismic, geological and other information relating to
+a property; 
+• 
+our ability to retain the personnel necessary to properly evaluate seismic and other
+information relating to a property; 
+• 
+the location of, and our ability to access, platforms, pipelines and other facilities
+used to produce and transport oil and gas production; 
+• 
+the standards we establish for the minimum projected return on an investment of our
+capital; and 
+• 
+the availability of alternate fuel sources. 
+Our competitors include major integrated oil companies, substantial independent energy companies,
+and affiliates of major interstate and intrastate pipelines and national and local gas gatherers,
+many of which possess greater financial, technological and other resources than we do.
+Our competitors may use superior technology, which we may be unable to afford or which would
+require costly investment by us in order to compete. Our industry is subject to rapid and
+significant advancements in technology, including the introduction of new products and services
+using new technologies. As our competitors use or develop new technologies, we may be placed at a
+competitive disadvantage, and competitive pressures may force us to implement new technologies at a
+substantial cost. In addition, our competitors may have greater financial, technical and personnel
+resources that allow them to enjoy technological advantages and may in the future allow them to
+implement new technologies before we can. We cannot be certain that we will be able to implement
+technologies on a timely basis or at a cost that is acceptable to us. One or more of the
+technologies that we currently use or that we may implement in the future may become obsolete, and
+we may be adversely affected. For example, marine seismic acquisition technology has been
+characterized by rapid technological advancements in recent years, and further significant
+technological developments could substantially impair our 3-D seismic data’s value.
+6
+Table of Contents 
+We may not be able to replace our reserves or generate cash flows if we are unable to raise
+capital. We will be required to make substantial capital expenditures to develop our existing
+reserves, and to discover new oil and gas reserves. Historically, we have financed these
+expenditures primarily with cash from operations, proceeds from bank borrowings and proceeds from
+the sale of debt and equity securities. See “Management’s Discussion and Analysis of Financial
+Condition and Results of Operations ¾ Liquidity and Capital Resources” for a discussion of
+our capital budget. We cannot assure you that we will be able to raise capital in the future. We
+also make offers to acquire oil and gas properties in the ordinary course of our business. If these
+offers are accepted, our capital needs may increase substantially.
+We expect to continue using our senior secured credit facility to borrow funds to supplement our
+available cash. The amount we may borrow under our senior secured credit facility may not exceed a
+borrowing base determined by the lenders under such facility based on their projections of our
+future production, production costs, taxes, commodity prices and any other factors deemed relevant
+by our lenders. We cannot control the assumptions the lenders use to calculate our borrowing base.
+The lenders may, without our consent, adjust the borrowing base semiannually or in situations where
+we purchase or sell assets or issue debt securities. If our borrowings under the senior secured
+credit facility exceed the borrowing base, the lenders may require that we repay the excess. If
+this were to occur, we might have to sell assets or seek financing from other sources. Sales of
+assets could further reduce the amount of our borrowing base. We cannot assure you that we would be
+successful in selling assets or arranging substitute financing. If we were not able to repay
+borrowings under our senior secured credit facility to reduce the outstanding amount to less than
+the borrowing base, we would be in default under our senior secured credit facility. For a
+description of our senior secured credit facility and its principal terms and conditions, see
+“Management’s Discussion and Analysis of Financial Condition and Results of Operations
+¾ Liquidity and Capital Resources” and Note 5 to our Consolidated Financial Statements.
+Our decision to drill a prospect is subject to a number of factors and we may decide to alter our
+drilling schedule or not drill at all. A prospect is a property on which we have identified what
+our geoscientists believe, based on available seismic and geological information, to be indications
+of hydrocarbons. Our prospects are in various stages of evaluation, ranging from a prospect which
+is ready to drill to a prospect which will require substantial additional seismic data processing
+and interpretation. Whether we ultimately drill a prospect may depend on the following factors:
+• 
+receipt of additional seismic data or the reprocessing of existing data; 
+• 
+material changes in oil or gas prices; 
+• 
+the costs and availability of drilling rigs; 
+• 
+the success or failure of wells drilled in similar formations or which would use the
+same production facilities; 
+• 
+availability and cost of capital; 
+• 
+changes in the estimates of the costs to drill or complete wells; 
+• 
+our ability to attract other industry partners to acquire a portion of the working
+interest to reduce exposure to costs and drilling risks; and 
+• 
+decisions of our joint working interest owners. 
+We will continue to gather data about our prospects and it is possible that additional information
+may cause us to alter our drilling schedule or determine that a prospect should not be pursued at
+all. You should understand that our plans regarding our prospects are subject to change.
+7
+Table of Contents 
+Weather, unexpected subsurface conditions, and other unforeseen operating hazards may adversely
+impact our ability to conduct business. There are many operating hazards in exploring for and
+producing oil and gas, including:
+• 
+our drilling operations may encounter unexpected formations or pressures, which could
+cause damage to equipment or personal injury; 
+• 
+we may experience equipment failures which curtail or stop production; 
+• 
+we could experience blowouts or other damages to the productive formations that may
+require a well to be re-drilled or other corrective action to be taken; and 
+• 
+because of these or other events, we could experience environmental hazards, including
+oil spills, gas leaks, and ruptures. 
+In the event of any of the foregoing, we may be subject to interrupted production or substantial
+environmental liability due to injury to or loss of life, damage to or destruction of property,
+natural resources and equipment, pollution and other environmental damage, investigation and
+remediation requirements. Moreover, a substantial portion of our operations are offshore and are
+subject to a variety of risks peculiar to the marine environment such as capsizing, collisions,
+hurricanes and other adverse weather conditions. These conditions can cause substantial damage to
+facilities and interrupt production. Offshore operations are also subject to more extensive
+governmental regulation.
+We cannot assure you that we will be able to maintain adequate insurance at rates we consider
+reasonable to cover our possible losses from operating hazards. The occurrence of a significant
+event not fully insured or indemnified against could materially and adversely affect our financial
+condition and results of operations.
+We may not have production to offset hedges; by hedging, we may not benefit from price increases. 
+Part of our business strategy is to reduce our exposure to the volatility of oil and gas prices by
+hedging a portion of our production. In a typical hedge transaction, we will have the right to
+receive from the other parties to the hedge the excess of the fixed price specified in the hedge
+over a floating price based on a market index, multiplied by the quantity hedged. If the floating
+price exceeds the fixed price, we are required to pay the other parties this difference multiplied
+by the quantity hedged. We are required to pay the difference between the floating price and the
+fixed price when the floating price exceeds the fixed price regardless of whether we have
+sufficient production to cover the quantities specified in the hedge. Significant reductions in
+production at times when the floating price exceeds the fixed price could require us to make
+payments under the hedge agreements even though such payments are not offset by sales of
+production. Hedging will also prevent us from receiving the full advantage of increases in oil or
+gas prices above the fixed amount specified in the hedge. We also enter into price “collars” to
+reduce the risk of changes in oil and gas prices. Under a collar, no payments are due by either
+party so long as the market price is above a floor set in the collar and below a ceiling. If the
+price falls below the floor, the counter-party to the collar pays the difference to us and if the
+price is above the ceiling, we pay the counter-party
+the difference. Another type of hedging contract we have entered into is a put contract. Under a
+put, if the price falls below the set floor price, the counter-party to the contract pays the
+difference to us. See “Quantitative and Qualitative Disclosures About Market Risks” for a
+discussion of our hedging practices.
+Compliance with environmental and other government regulations could be costly and could negatively
+impact production. Our operations are subject to numerous laws and regulations governing the
+operation and maintenance of our facilities and the discharge of materials into the environment or
+otherwise relating to environmental protection. For a discussion of the material regulations
+applicable to
+8
+Table of Contents 
+us, see “Federal Regulations,” “State Regulations,” and “Environmental Regulations.”
+These laws and regulations may:
+• 
+require that we acquire permits before commencing drilling; 
+• 
+restrict the substances that can be released into the environment in connection with
+drilling and production activities; 
+• 
+limit or prohibit drilling activities on protected areas such as wetlands or wilderness
+areas; and 
+• 
+require remedial measures to mitigate pollution from former operations, such as
+dismantling abandoned production facilities. 
+Under these laws and regulations, we could be liable for personal injury and clean-up costs and
+other environmental and property damages, as well as administrative, civil and criminal penalties.
+We maintain limited insurance coverage for sudden and accidental environmental damages. We do not
+believe that insurance coverage for environmental damages that occur over time is available at a
+reasonable cost. Also, we do not believe that insurance coverage for the full potential liability
+that could be caused by sudden and accidental environmental damages is available at a reasonable
+cost. Accordingly, we may be subject to liability or we may be required to cease production from
+properties in the event of environmental damages.
+Factors beyond our control affect our ability to market production and our financial results. The
+ability to market oil and gas from our wells depends upon numerous factors beyond our control.
+These factors include:
+• 
+the extent of domestic production and imports of oil and gas; 
+• 
+the proximity of the gas production to gas pipelines; 
+• 
+the availability of pipeline capacity; 
+• 
+the demand for oil and gas by utilities and other end users; 
+• 
+the availability of alternative fuel sources; 
+• 
+the effects of inclement weather; 
+• 
+state and federal regulation of oil and gas marketing; and 
+• 
+federal regulation of gas sold or transported in interstate commerce. 
+Because of these factors, we may be unable to market all of the oil or gas we produce. In addition,
+we may be unable to obtain favorable prices for the oil and gas we produce.
+If oil and gas prices decrease, we may be required to take writedowns of the carrying value of our
+oil and gas properties. We may be required to writedown the carrying value of our oil and gas
+properties when oil and gas prices are low or if we have substantial downward adjustments to our
+estimated net proved reserves, increases in our estimates of development costs or deterioration in
+our exploration results. Under the full-cost method which we use to account for our oil and gas
+properties, the net capitalized costs of our oil and gas properties may not exceed the present
+value, discounted at 10%, of future net cash flows from estimated net proved reserves, using period end oil and gas prices or
+prices as of the date of our auditor’s report, plus the lower of cost or fair market value of our
+unproved properties. If net capitalized costs of our oil and gas properties exceed this limit, we
+must charge the amount of the excess to earnings. This type of charge will not affect our cash
+flows, but will reduce the book value of our stockholders’ equity. We review the carrying value of
+our properties quarterly, based on prices in effect as of the end of each quarter or at the time of
+reporting our results. Once incurred, a writedown of oil and gas properties is not reversible at a
+later date, even if prices increase.
+9
+Table of Contents 
+There are inherent limitations in all control systems, and misstatements due to error or fraud that
+could seriously harm our business may occur and not be detected. Our management, including our
+Chief Executive Officer and Chief Financial Officer, does not expect that our internal controls and
+disclosure controls will prevent all possible error and all fraud. A control system, no matter how
+well conceived and operated, can provide only reasonable, not absolute, assurance that the
+objectives of the control system are met. In addition, the design of a control system must reflect
+the fact that there are resource constraints and the benefit of controls must be relative to their
+costs. Because of the inherent limitations in all control systems, an
+evaluation of controls can only
+provide reasonable assurance that all material control issues and instances of fraud, if any, in our company
+have been detected. These inherent limitations include the realities that judgments in
+decision-making can be faulty and that breakdowns can occur because of simple error or mistake.
+Further, controls can be circumvented by the individual acts of some persons or by collusion of two
+or more persons. The design of any system of controls is based in part upon certain assumptions
+about the likelihood of future events, and there can be no assurance that any design will succeed
+in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system,
+misstatements due to error or fraud may occur and not be detected. A failure of our controls and
+procedures to detect error or fraud could seriously harm our business and results of operations.
+Forward-Looking Statements 
+In this report, we have made many forward-looking statements. We cannot assure you that the plans,
+intentions or expectations upon which our forward-looking statements are based will occur. Our
+forward-looking statements are subject to risks, uncertainties and assumptions, including those
+discussed elsewhere in this report. Forward-looking statements include statements regarding:
+• 
+our oil and gas reserve quantities, and the discounted present value of these
+reserves; 
+• 
+the amount and nature of our capital expenditures; 
+• 
+drilling of wells; 
+• 
+the timing and amount of future production and operating costs; 
+• 
+business strategies and plans of management; and 
+• 
+prospect development and property acquisitions. 
+Some of the risks, which could affect our future results and could cause results to differ
+materially from those expressed in our forward-looking statements, include:
+• 
+general economic conditions; 
+• 
+the volatility of oil and natural gas prices; 
+• 
+the uncertainty of estimates of oil and natural gas reserves; 
+• 
+the impact of competition; 
+• 
+the availability and cost of seismic, drilling and other equipment; 
+• 
+operating hazards inherent in the exploration for and production of oil and natural
+gas; 
+• 
+difficulties encountered during the exploration for and production of oil and
+natural gas; 
+• 
+difficulties encountered in delivering oil and natural gas to commercial markets; 
+• 
+changes in customer demand and producers’ supply; 
+• 
+the uncertainty of our ability to attract capital; 
+• 
+compliance with, or the effect of changes in, the extensive governmental
+regulations regarding the oil and natural gas business; 
+• 
+actions of operators of our oil and gas properties; and 
+• 
+weather conditions. 
+10
+Table of Contents 
+The information contained in this report, including the information set forth under the heading
+“Risk Factors,” identifies additional factors that could affect our operating results and
+performance. We urge you to carefully consider these factors and the other cautionary statements in
+this report. Our forward-looking statements speak only as of the date made, and we have no
+obligation to update these forward-looking statements.
+Corporate Offices 
+Our headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned
+space. We also maintain a business office in Houston, Texas, and own or lease field offices in the
+area of the major fields in which we operate properties or have a significant interest. Replacement
+of any of our leased offices would not result in material expenditures by us as alternative
+locations to our leased space are anticipated to be readily available . 
+Employees 
+We had 87 employees as of December 31, 2004, none of whom are currently represented by a union. We
+believe that we have good relations with our employees. We employ six petroleum engineers and
+seven petroleum geoscientists.
+Federal Regulations 
+Sales of Natural Gas. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act
+deregulated prices for all “first sales” of natural gas. Thus, all sales of gas by us may be made
+at market prices, subject to applicable contract provisions.
+Transportation of Natural Gas. The rates, terms and conditions applicable to the interstate
+transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory
+Commission (“FERC”) under the Natural Gas Act (“NGA”), as well as under section 311 of the Natural
+Gas Policy Act (“NGPA”). Since 1985, primarily pursuant to Order Nos. 436 and 636, the FERC has
+implemented regulations intended to make natural gas transportation more accessible to gas buyers
+and sellers on an open-access, non-discriminatory basis.
+In February, 2000, the FERC issued Order No. 637, a rule designed to continue the restructuring of
+the gas industry. Order No. 637 revised the FERC’s policies governing interstate pipeline
+transportation rates and penalties and refined the regulatory framework governing transportation
+terms and conditions to improve open access transportation. The rule has been implemented on a
+pipeline-by-pipeline basis in individual compliance proceedings, almost all of which have been
+settled or have otherwise been terminated.
+In Order No. 2004, issued on November 25, 2003, the FERC issued standards of conduct covering
+regulated interstate pipelines and public utilities (“Transmission Providers”) to govern the
+relationships between regulated Transmission Providers and all of their energy affiliates. Among
+other things, these measures are intended to increase confidence and transparency in the gas market in the wake of recent events
+involving anticompetitive behavior and market abuse.
+On February 12, 2004, the FERC issued a notice of proposed rulemaking in Docket No. RM04-4 designed
+to standardize the procedures for determining the creditworthiness and collateral required of
+shippers on interstate pipelines and to adopt certain standards published by the North American
+Energy Standards Board
+11
+Table of Contents 
+with respect to shipper creditworthiness. The standards are intended to
+facilitate and increase transparency in the creditworthiness evaluation process.
+The FERC is presently reviewing in Docket No. PL04-3, a general policy inquiry, and in individual
+interstate gas pipeline proceedings, whether it should adopt quality and “interchangeability”
+standards for natural gas delivered through interstate pipelines. In general, the issue in these
+proceedings is whether the FERC should impose quality standards for individual pipelines or on a
+broader basis or otherwise regulate the composition and quality of natural gas transported through
+the interstate pipeline system. At the present time the approach that the FERC will take in these
+proceedings and the potential impact on gas supply and on the Company are not clear. In addition,
+on November 22, 2004, the FERC initiated an inquiry on selective discounting for shippers by
+interstate natural gas pipelines. The FERC is focusing the inquiry on whether such discounting
+should continue to be supported by the prices paid by other customers as is the case under current
+FERC policy. One key issue in this inquiry is whether the existing FERC policy should be continued
+for shippers who have access to more than one interstate gas pipeline. Because the inquiry has not
+been completed, its effect on the availability of discounted interstate pipeline transportation
+rates for shippers of natural gas is unclear.
+On October 10, 2003, the U.S. Court of Appeals for the District of Columbia Circuit affirmed a
+district court ruling that severely circumscribed the FERC’s authority under the Outer Continental
+Shelf Lands Act (“OCSLA”). The court found that OCSLA confers upon the Secretary of Interior, not
+the FERC, authority to enforce open access conditions under OCSLA. The FERC retains authority
+under the Natural Gas Act (“NGA”) to enforce open access transportation conditions over natural gas
+pipeline facilities on the Outer Continental Shelf (“OCS”), and under limited conditions over
+natural gas gathering facilities owned directly or indirectly by natural gas pipeline companies.
+The FERC has no authority under the NGA to enforce open access conditions on gathering facilities
+owned by companies that are not affiliated with natural gas pipeline companies. The FERC has no
+authority under the Interstate Commerce Act (“ICA”) to regulate oil pipelines that lie wholly on
+the OCS. In response to the court’s opinion, on April 12, 2004 the Minerals Management Service
+(“MMS”) of the Department of Interior (“DOI”) issued an Advanced Notice of Proposed Rulemaking
+(ANOPR”) requesting comments to assist it in potentially amending its regulations regarding how the
+DOI should ensure that pipelines transporting oil or gas under permits, licenses, easements or
+rights-of-way across the OCS provide open and non-discriminatory access to both owner and non-owner
+shippers under OCSLA. Various parties filed comments in response to the ANOPR. The MMS has not
+yet issued a follow-up Notice of Proposed Rulemaking. It is not clear what regulatory regime the
+MMS will impose to enforce open access transportation on the OCS under OCSLA, nor what impact any
+particular regulatory regime may have upon the ability of the Company to obtain transportation of
+its natural gas and oil production to markets.
+Sales and Transportation of Crude Oil. Sales of crude oil and condensate can be made by us at
+market prices not subject at this time to price controls. The price that we receive from the sale
+of these products will be affected by the cost of transporting the products to market. The rates,
+terms, and conditions applicable to the interstate transportation of oil and related products by
+interstate pipelines are regulated by the FERC under the ICA. Pursuant to the Energy Policy Act of
+1992, which “grandfathered” certain existing rates, the FERC presently regulates interstate oil
+pipeline rates under a light-handed, streamlined regulatory regime where interstate pipeline rates
+can be adjusted annually using an index ceiling based upon the producer price
+index. The FERC recently modified the formula for calculating the index such that the index
+ceilings are now set slightly higher than under the original formula. The FERC will also, under
+defined circumstances, permit alternative ratemaking methodologies for interstate oil pipelines
+such as the use of cost of service rates, settlement rates, and market-based rates. Market-based
+rates will be permitted to the extent the pipeline can demonstrate that it lacks significant market
+power in the market in which it proposes to charge
+12
+Table of Contents 
+market-based rates. The cumulative effect that
+these rules have had on moving our production to market has not been material.
+As stated above, as a result of a recent decision by the U.S. Court of Appeals for the District of
+Columbia Circuit with respect to the transportation of oil and condensate on or across the OCS, the
+DOI, not the FERC, has the authority under OCSLA to enforce open access conditions on oil pipelines
+lying wholly on the OCS.
+Legislative Proposals. In the past, Congress has been active in the area of natural gas
+regulation. There are legislative proposals pending in Congress and in various state legislatures
+which, if enacted, could significantly affect the petroleum industry. At the present time it is
+difficult to predict what proposals, if any, might actually be enacted by Congress or the various
+state legislatures and what effect, if any, such proposals might have on our operations.
+Federal, State or Indian Leases. In the event we conduct operations on federal, state or Indian
+oil and gas leases, such operations must comply with numerous regulatory restrictions, including
+various nondiscrimination statutes, royalty and related valuation requirements, and certain of such
+operations must be conducted pursuant to on-site security regulations and other appropriate permits
+issued by the Bureau of Land Management (“BLM”) or Minerals Management Service (“MMS”) or other
+appropriate federal or state agencies.
+The Company’s OCS leases in federal waters are administered by the MMS and require compliance with
+detailed MMS regulations and orders. The MMS has promulgated regulations implementing restrictions
+on various production-related activities, including restricting the flaring or venting of natural
+gas. Under certain circumstances, the MMS may require our operations on federal leases to be
+suspended or terminated. Any such suspension or termination could materially and adversely affect
+our financial condition and operations. On March 15, 2000, the MMS issued a final rule effective
+June 1, 2000 which amends its regulations governing the calculation of royalties and the valuation
+of crude oil produced from federal leases. Among other matters, this rule amends the valuation
+procedure for the sale of federal royalty oil by eliminating posted prices as a measure of value
+and relying instead on arm’s length sales prices and spot market prices as market value indicators.
+Because we sell our production in the spot market and therefore pay royalties on production from
+federal leases, it is not anticipated that this final rule will have any substantial impact on us.
+The Mineral Leasing Act of 1920 (“Mineral Act”) prohibits direct or indirect ownership of any
+interest in federal onshore oil and gas leases by a foreign citizen of a country that denies
+“similar or like privileges” to citizens of the United States. Such restrictions on citizens of a
+“non-reciprocal” country include ownership or holding or controlling stock in a corporation that
+holds a federal onshore oil and gas lease. If this restriction is violated, the corporation’s
+lease can be canceled in a proceeding instituted by the United States Attorney General. Although
+the regulations of the BLM (which administers the Mineral Act) provide for agency designations of
+non-reciprocal countries, there are presently no such designations in effect. We own interests in
+numerous federal onshore oil and gas leases. It is possible that some of our stockholders may be
+citizens of foreign countries, which at some time in the future might be determined to be
+non-reciprocal under the Mineral Act.
+State Regulations 
+Most states regulate the production and sale of oil and natural gas, including requirements for
+obtaining drilling permits, the method of developing new fields, the spacing and operation of wells
+and the prevention of waste of oil and gas resources. The rate of production may be regulated and
+the maximum daily
+13
+Table of Contents 
+production allowable from both oil and gas wells may be established on a market
+demand or conservation basis or both.
+We may enter into agreements relating to the construction or operation of a pipeline system for the
+transportation of natural gas. To the extent that such gas is produced, transported and consumed
+wholly within one state, such operations may, in certain instances, be subject to the jurisdiction
+of such state’s administrative authority charged with the responsibility of regulating intrastate
+pipelines. In such event, the rates which we could charge for gas, the transportation of gas, and
+the costs of construction and operation of such pipeline would be impacted by the rules and
+regulations governing such matters, if any, of such administrative authority. Further, such a
+pipeline system would be subject to various state and/or federal pipeline safety regulations and
+requirements, including those of, among others, the Department of Transportation. Such regulations
+can increase the cost of planning, designing, installing and operating such facilities. The impact
+of such pipeline safety regulations would not be any more adverse to us than it would be to other
+similar owners or operators of such pipeline facilities.
+Environmental Regulations 
+General. Our activities are subject to federal, state and local laws and regulations governing
+environmental quality and pollution control. Although no assurances can be made, we believe that,
+absent the occurrence of an extraordinary event, compliance with existing federal, state and local
+laws, rules and regulations regulating the release of materials into the environment or otherwise
+relating to the protection of the environment will not have a material effect upon our capital
+expenditures, earnings or competitive position with respect to our existing assets and operations.
+We cannot predict what effect future regulation or legislation, enforcement policies, and claims
+for damages to property, employees, other persons and the environment resulting from our operations
+could have on our activities.
+Our activities with respect to natural gas facilities, including the operation and construction of
+pipelines, plants and other facilities for transporting, processing, treating or storing natural
+gas and other products, are subject to stringent environmental regulation by state and federal
+authorities including the United States Environmental Protection Agency (“EPA”). Such regulation
+can increase the cost of planning, designing, installing and operating such facilities. In most
+instances, the regulatory requirements relate to water and air pollution control measures.
+Although we believe that compliance with environmental regulations will not have a material adverse
+effect on us, risks of substantial costs and liabilities are inherent in oil and gas production
+operations, and there can be no assurance that significant costs and liabilities will not be
+incurred. Moreover, it is possible that other developments, such as stricter environmental laws and
+regulations, and claims for damages to property or persons resulting from oil and gas production,
+would result in substantial costs and liabilities to us.
+Solid and Hazardous Waste. We currently own or lease, and in the past owned or leased, properties
+that have been used for the exploration and production of oil and gas for many years. Although we
+have utilized operating and disposal practices that were standard in the industry at the time,
+hydrocarbons or other solid wastes may have been disposed or released on or under the properties
+owned or leased by us or on or under locations where such wastes have been taken for disposal. In
+addition, many of these properties have been operated by third parties. We have no control over
+such entities’ treatment of hydrocarbons or other solid wastes and the manner in which such
+substances may have been disposed or released. State and federal laws applicable to oil and gas
+wastes and properties have gradually become stricter over time. Under new laws,
+we could be required to remediate property, including groundwater, containing or impacted by
+previously disposed wastes (including wastes disposed or released by prior owners or operators, or
+property
+14
+Table of Contents 
+contamination, including groundwater contamination by prior owners or operators) or to
+perform remedial plugging operations to prevent future or mitigate existing contamination.
+We generate wastes, including hazardous wastes that are subject to the federal Resource
+Conservation and Recovery Act (“RCRA”) and comparable state statutes. The EPA and various state
+agencies have limited the disposal options for certain wastes, including wastes designated as
+hazardous under the RCRA and similar state statutes (“Hazardous Wastes”). Furthermore, it is
+possible that certain wastes generated by our oil and gas operations that are currently exempt from
+treatment as Hazardous Wastes may in the future be designated as Hazardous Wastes under RCRA or
+other applicable statutes and, therefore, may be subject to more rigorous and costly disposal
+requirements.
+Superfund. The federal Comprehensive Environmental Response, Compensation and Liability Act
+(“CERCLA”), also known as the “Superfund” law, generally imposes joint and several liability for
+costs of investigation and remediation and for natural resource damages, without regard to fault or
+the legality of the original conduct, on certain classes of persons with respect to the release
+into the environment of substances designated under CERCLA as hazardous substances (“Hazardous
+Substances”). These classes of persons, or so-called potentially responsible parties (“PRPs”),
+include the current and certain past owners and operators of a facility where there has been a
+release or threat of release of a Hazardous Substance and persons who disposed of or arranged for
+the disposal of Hazardous Substances found at a site. CERCLA also authorizes the EPA and, in some
+cases, third parties to take actions in response to threats to the public health or the environment
+and to seek to recover from the PRPs the costs of such action. Although CERCLA generally exempts
+“petroleum” from the definition of Hazardous Substance, in the course of its operations, we have
+generated and will generate wastes that may fall within CERCLA’s definition of Hazardous Substance.
+We may also be the owner or operator of sites on which Hazardous Substances have been released.
+To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under
+CERCLA. We also do not know of any prior owners or operators of our properties that are named as
+PRPs related to their ownership or operation of such properties. Certain states, including
+Louisiana, have comparable statutes. In the event contamination is discovered at a site on which
+we are or have been an owner or operator, we could be liable for costs of investigation and
+remediation and natural resource damages.
+Clean Water Act . The Clean Water Act (“CWA”) imposes restrictions and strict controls regarding
+the discharge of wastes including produced waters and other oil and natural gas wastes, into waters
+of the United States, a term broadly defined. These controls have become more stringent over the
+years, and it is probable that additional restrictions will be imposed in the future. Permits must
+be obtained to discharge pollutants into federal waters. The CWA provides for civil, criminal and
+administrative penalties for unauthorized discharges of oil and hazardous substances and of other
+pollutants. It imposes substantial potential liability for the costs of removal or remediation
+associated with discharges of oil or hazardous substances and other pollutants. State laws
+governing discharges to water also provide varying civil, criminal and administrative penalties and
+impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous
+substances, into state waters. In addition, the EPA has promulgated regulations that may require
+us to obtain permits to discharge storm water runoff, including discharges associated with
+construction activities. In the event of an unauthorized discharge of wastes, we may be liable for
+penalties and costs.
+Oil Pollution Act. The Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill
+provisions of the CWA, imposes certain duties and liabilities on certain “responsible parties”
+related to the prevention of oil spills and damages resulting from such spills in or threatening
+United States waters or adjoining shorelines. A liable “responsible party” includes the owner or
+operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the
+substantial threat of discharge, or in the case of offshore
+facilities, the lessee or permittee of the area in which a discharging facility is located. The
+OPA assigns joint
+15
+Table of Contents 
+and several liability, without regard to fault, to each liable party for oil
+removal costs and a variety of public and private damages. Although defenses and limitations exist
+to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial
+threat of discharge, we may be liable for costs and damages.
+The OPA also imposes ongoing requirements on a responsible party, including proof of financial
+responsibility to cover at least some costs in a potential spill. Certain amendments to the OPA
+that were enacted in 1996 require owners and operators of offshore facilities that have a worst
+case oil spill potential of more than 1,000 barrels to demonstrate financial responsibility in
+amounts ranging from $10 million in specified state waters and $35 million in federal OCS waters,
+with higher amounts, up to $150 million based upon worst case oil-spill discharge volume
+calculations. We believe that we have established adequate proof of financial responsibility for
+our offshore facilities.
+Air Emissions. Our operations are subject to local, state and federal regulations for the control
+of emissions from sources of air pollution. Federal and state laws require new and modified
+sources of air pollutants to obtain permits prior to commencing construction. Major sources of air
+pollutants are subject to more stringent, federally imposed requirements including additional
+permits. Federal and state laws designed to control hazardous (toxic) air pollutants, might
+require installation of additional controls. Administrative enforcement actions for failure to
+comply strictly with air pollution regulations or permits are generally resolved by payment of
+monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies
+could bring lawsuits for civil penalties or require us to forego construction, modification or
+operation of certain air emission sources.
+Coastal Coordination. There are various federal and state programs that regulate the conservation
+and development of coastal resources. The federal Coastal Zone Management Act (“CZMA”) was passed
+in 1972 to preserve and, where possible, restore the natural resources of the Nation’s coastal
+zone. The CZMA provides for federal grants for state management programs that regulate land use,
+water use and coastal development.
+Various states, such as Alabama, Louisiana and Texas, also have coastal management programs, which
+provide for, among other things, the coordination among local and state authorities to protect
+coastal resources through regulating land use, water, and coastal development. Coastal management
+programs also may provide for the review of state and federal agency rules and agency actions for
+consistency with the goals and policies of the state coastal management plan. This review may
+impact agency permitting and review activities and add an additional layer of review to certain
+activities undertaken by us.
+OSHA and other Regulations. We are subject to the requirements of the federal Occupational Safety
+and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the
+EPA community right-to-know regulations under Title III of CERCLA and similar state statutes
+require us to organize and/or disclose information about hazardous materials used, stored or
+produced in our operations.
+Our management believes that we are in substantial compliance with current applicable environmental
+laws and regulations and that continued compliance with existing requirements would not have a
+material adverse impact on us.
+Commitments and Contingencies 
+The Company’s activities are subject to federal, state and local laws and regulations governing
+environmental quality and pollution control. Although no assurances can be made, the Company
+believes
+16
+Table of Contents 
+that, absent the occurrence of an extraordinary event, compliance with existing federal, state and
+local laws, rules and regulating the release of materials in the environment or otherwise relating
+to the protection of the environment will not have a material effect upon the capital expenditures,
+earnings or the competitive position of the Company with respect to its existing assets and
+operations. The Company cannot predict what effect additional regulation or legislation,
+enforcement polices thereunder, and claims for damages to property, employees, other person, and
+the environment resulting from the Company’s operations could have on its activities.
+Property Summary 
+We are engaged in the exploration, development, acquisition and production of oil and gas
+properties and provide oil and gas property management services for other investors. Our
+properties are concentrated offshore in the Gulf of Mexico and onshore, primarily, in Louisiana and
+Alabama. We have historically increased our reserves and production by focusing primarily on low to
+moderate risk exploration and acquisition opportunities in the Gulf of Mexico shelf area. In 1998,
+we expanded our area of exploration to include the Gulf of Mexico deepwater area. As of December
+31, 2004, our estimated net proved reserves totaled 19.7 million barrels of oil (“MMBbl”) and 72.6
+billion cubic feet of natural gas (“Bcf”), with a pre-tax present value, discounted at 10%, of the
+estimated future net revenues based on constant prices in effect at year-end (“Discounted Cash
+Flow”) of $612.6 million. Oil constitutes approximately 62% on an equivalent basis of our total
+estimated proved reserves and approximately 50% of our total estimated proved reserves are proved
+developed reserves.
+Our Medusa (Mississippi Canyon Blocks 538/582) and Habanero (Garden Banks Block 341) discoveries
+began production in the fourth quarter of 2003. A detailed discussion of each of these properties
+is provided in the “Significant Properties” section of this report. These two deepwater
+discoveries were primarily responsible for an increase in our 2004 production by approximately 57%
+from 2003 levels.
+17
+Table of Contents 
+Significant Properties 
+The following table shows discounted cash flows and estimated net proved oil and gas reserves by
+major field, within the focus area, for our eight largest fields and for all other properties
+combined at December 31, 2004.
+Pre-tax 
+Estimated Net Proved Reserves 
+Discounted 
+Present 
+Oil 
+Gas 
+Total 
+Value 
+Operator 
+(MBbls) 
+(MMcf) 
+(MMcfe) 
+($000) 
+(a)(b) 
+Gulf of Mexico Deepwater: 
+Mississippi Canyon Blocks 538/582
+“Medusa” 
+Murphy 
+6,945 
+4,970 
+46,640 
+$ 
+155,829 
+Garden Banks Block 341
+“Habanero” 
+Shell 
+4,070 
+10,390 
+34,812 
+139,153 
+Garden Banks Blocks
+738/782/826/827
+“Entrada” 
+BP 
+7,772 
+29,126 
+75,760 
+219,368 
+Gulf of Mexico Shelf: 
+Mobile Blocks 863/864/907/908 
+Callon 
+— 
+4,068 
+4,068 
+9,929 
+Mobile Blocks 952/953/955 
+Callon 
+— 
+9,362 
+9,362 
+29,199 
+North Padre Island Block 913 
+Callon 
+2 
+3,457 
+3,467 
+11,133 
+High Island Block 119 
+Kerr-McGee 
+32 
+2,999 
+3,192 
+18,560 
+Onshore and Other: 
+Big Escambia Creek 
+Vintage 
+387 
+1,627 
+3,949 
+8,970 
+Other 
+Various 
+540 
+6,620 
+9,858 
+20,454 
+Total Net Proved Reserves 
+19,748 
+72,619 
+191,108 
+$ 
+612,595 
+(a) 
+Represents the present value of future net cash flows before deduction of federal income
+taxes, discounted at 10%, attributable to estimated net proved reserves as of December 31,
+2004, as set forth in the Company’s reserve reports prepared by its independent petroleum
+reserve engineers, Huddleston & Co., Inc. of Houston, Texas. 
+(b) 
+Includes a reduction for estimated plugging and abandonment costs that is reflected as a
+liability on our balance sheet at December 31, 2004, in accordance with Statement of Financial
+Accounting Standards No. 143. See the Oil and Gas Reserve table for the standardized measure
+of discounted future net cash flow which is a required calculation by the SEC. 
+18
+Table of Contents 
+Gulf of Mexico Deepwater 
+Medusa, Mississippi Canyon Blocks 538/582 
+Our Medusa deepwater discovery was announced in September 1999, after we drilled the initial test
+well in 2,235 feet of water to a total depth of 16,241 feet and encountered over 120 feet of pay in
+two intervals. Subsequent sidetrack drilling from the wellbore was used to determine the extent of
+the discovery and a second well was drilled in the first quarter of 2000 to further delineate the
+extent of the pay intervals. We own a 15% working interest, Murphy Exploration & Production
+Company, the operator, owns a 60% working interest and ENI Deepwater, LLC, owns the remaining 25%
+working interest.
+In 2001 a drilling program began which included four development wells and one sidetrack. The
+program included production casing being set on six wells to provide initial production take-points
+and was completed in the first half of 2002. The construction of a floating production system,
+spar, at Medusa was completed during the second quarter of 2003. The A-1 well was completed and
+tied into the spar and commenced production in late November 2003. The remaining five wells were
+completed and commenced production in 2004. During 2004 the field produced an average of 20.5
+million cubic feet of natural gas equivalent (“MMcfe”) per day net to us. The field is currently
+producing approximately 40,000 barrels of crude oil and 40 million cubic feet of natural gas
+(“MMcf”) per day, or 36.1 MMcfe per day net to our interest.
+In December 2003, we transferred our undivided 15% working interest in the spar production
+facilities to Medusa Spar LLC in exchange for cash proceeds of approximately $25 million and a 10%
+ownership interest in the LLC. A detailed discussion of this transaction is included in
+Management’s Discussion and Analysis of Financial Condition and Results of Operations-“Off-Balance
+Sheet Arrangements”.
+Habanero, Garden Banks Block 341 
+During February 1999, the initial test well on our Habanero deepwater discovery encountered over
+200 feet of net pay in two zones. Located in 2,000 feet of water, the well was drilled to a
+measured depth of 21,158 feet. We own an 11.25% working interest in the well. The well is operated
+by Shell Deepwater Development Inc., which owns a 55% working interest, with the remaining working
+interest being owned by Murphy.
+A field delineation program began in mid-year 2001, which included three sidetracks of the
+discovery well. Production casing was set on this well through one of the sidetracks to the
+Habanero 52 oil and gas sand and the Habanero 55 gas sand. Also, a development well was drilled in
+the summer of 2003 which provides a take-point for production from the Habanero 52 oil sand. By
+means of a sub-sea completion and tie back to an existing production facility in the area operated
+by Shell, production from the Habanero 52 oil sand commenced in late November 2003 and from the
+Habanero 55 gas sand in January 2004. In July the #2 well producing the Habanero 52 oil sand
+developed mechanical difficulties with a subsurface control value and was shut-in resulting in a
+significant loss of production. Repairs were completed and production was restored in late
+December. In addition, the #1 well producing the Habanero 55 gas sand was recompleted to the
+Habanero 55 oil sand in December. Our net production during 2004 from the Habanero field was
+approximately 11.1 MMcfe per day. The field is currently producing approximately 21,000 barrels of
+crude oil and 35 MMcf per day, or 15.5 MMcfe per day net to our interest.
+19
+Table of Contents 
+Entrada, Garden Banks Blocks 738/782/826/827 
+The Entrada discovery is located in approximately 4,500 feet of water in the Gulf of Mexico. Two
+wells and seven sidetracks have been drilled to date. The Entrada Area is characterized by a
+northwest plunging salt ridge with multiple stacked amplitudes trapped against the salt and various
+faults. We own a 20% working interest in this discovery with BP, the operator, holding the
+remaining working interest.
+An integrated project team has been formed by the working interest owners and is reviewing various
+plans for development of the field. One scenario is to negotiate a tie-in of Entrada into existing
+production facilities. The owners of an adjacent discovery have commenced production from
+facilities that will enable them to be a regional off-take point in Southeastern Garden Banks.
+These plans include handling third party tie-ins. Production from Entrada under this scenario
+could possibly commence in 2007.
+Gulf of Mexico Shelf 
+Mobile Blocks 863/864/ 907 
+We own an average 64.6% working interest in these blocks and we are the operator. The Mobile 864
+unit, in which we have a 66.4% working interest, has four producing wells, unit production
+facilities and covers portions of these three blocks. During 2004 the unit produced an average of
+2.9 MMcf per day net to us.
+Mobile Blocks 952/953/955 
+We own a 100% working interest in these three blocks and we are the operator. In the fourth
+quarter of 2001, we initiated a production acceleration program for Mobile Blocks 952, 953 and 955,
+which were being produced through the Mobile Block 864 unit facilities and were production
+constrained. An acceleration well was successfully drilled in the fourth quarter of 2001 and
+stand-alone production facilities were installed and production flow lines were rerouted to the new
+facilities. Production commenced through the new facilities in April 2002. In order to completely
+produce the proved reserves of the field we drilled a development well on Mobile Block 955 during
+the first quarter of 2004. Production from the field for 2004 was 14.7 MMcf per day net to us.
+High Island Block 119 
+An initial exploratory well and one development well were drilled and completed in 2004. First
+production began in the third quarter of 2004. An exploratory well in an offsetting fault block
+was spud late in the fourth quarter of 2004 and was completed in 2005. We own a 22% working
+interest and Westport Resources is the operator. Production for the fourth quarter of 2004 net to
+us was 3.7 MMcfe per day. Peak production should be reached by the end of the first quarter of
+2005 at a rate estimated to be 50 MMcfe per day, or 8.5 MMcfe per day net to our interest.
+North Padre Island Block 913 
+An exploratory well was drilled to a vertical depth of 8,082 feet in the fourth quarter of 2004 and
+found apparent natural gas pay in multiple intervals. Currently, the well is being completed and
+will be tied back to existing infrastructure on a nearby block. We are the operator and own a 50%
+working interest. First production is forecast to be in the third quarter of 2005.
+20
+Table of Contents 
+Onshore and Other 
+Big Escambia Creek 
+This gas field in south Alabama produces from the Smackover formation at depths ranging from 15,100
+to 15,600 feet and is operated by Vintage. We own an average working interest of 4.9% (5.5% net
+revenue interest), in six wells and a 2.2% average royalty interest in another five wells. This
+field produced 0.7 MMcfe per day net to our interest in 2004. The field has an estimated reserve
+life in excess of 10 years given current production rates.
+Other 
+We own various royalty and working interests in numerous onshore areas and the Gulf of Mexico other
+than the fields discussed above.
+Oil and Gas Reserves 
+The following table sets forth certain information about our estimated proved reserves as of the
+dates set forth below.
+Years Ended December 31, 
+2004 
+2003 
+2002 
+(In thousands) 
+Proved developed: 
+Oil (Bbls) 
+10,292 
+9,919 
+1,056 
+Gas (Mcf) 
+33,982 
+31,415 
+37,631 
+Mcfe 
+95,735 
+90,926 
+43,966 
+Proved undeveloped: 
+Oil (Bbls) 
+9,456 
+13,790 
+22,987 
+Gas (Mcf) 
+38,637 
+43,276 
+53,908 
+Mcfe 
+95,373 
+126,017 
+191,833 
+Total proved: 
+Oil (Bbls) 
+19,748 
+23,709 
+24,043 
+Gas (Mcf) 
+72,619 
+74,691 
+91,539 
+Mcfe 
+191,108 
+216,943 
+235,799 
+Estimated
+pre-tax future net cash flows (a) 
+$ 
+892,145 
+$ 
+838,847 
+$ 
+970,199 
+Pre-tax discounted present value (a) 
+$ 
+612,595 
+$ 
+570,463 
+$ 
+623,946 
+Standardized measure of discounted future
+net cash flows(a) 
+$ 
+515,893 
+$ 
+519,026 
+$ 
+556,046 
+(a) 
+Includes a reduction for estimated plugging and abandonment costs that is reflected as
+a liability on our balance sheet at December 31, 2004, in accordance with Statement of
+Financial Accounting Standards No. 143. 
+21
+Table of Contents 
+Our independent reserve engineers, Huddleston & Co., Inc., prepared the estimates of the proved
+reserves and the future net cash flows and present value thereof attributable to such proved
+reserves. Reserves were estimated using oil and gas prices and production and development costs in
+effect on December 31 of each such year, without escalation, and were otherwise prepared in
+accordance with Securities and Exchange Commission regulations regarding disclosure of oil and gas
+reserve information.
+There are numerous uncertainties inherent in estimating quantities of proved reserves, including
+many factors beyond our control or the control of the reserve engineers. Reserve engineering is a
+subjective process of estimating underground accumulations of oil and gas that cannot be measured
+in an exact manner. The accuracy of any reserve or cash flow estimate is a function of the quality
+of available data and of engineering and geological interpretation and judgment. Estimates by
+different engineers often vary, sometimes significantly. In addition, physical factors, such as
+the results of drilling, testing and production subsequent to the date of an estimate, as well as
+economic factors, such as an increase or decrease in product prices that renders production of such
+reserves more or less economic, may justify revision of such estimates. Accordingly, reserve
+estimates could be different from the quantities of oil and gas that are ultimately recovered.
+We have not filed any reports with other federal agencies which contain an estimate of total proved
+net oil and gas reserves during our last fiscal year.
+Present Activities and Productive Wells 
+The following table sets forth the wells we have drilled and completed during the periods
+indicated. All such wells were drilled in the continental United States primarily in federal and
+state waters in the Gulf of Mexico.
+Years Ended December 31, 
+2004 
+2003 
+2002 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development: 
+Oil 
+— 
+— 
+2 
+.23 
+2 
+.30 
+Gas 
+2 
+1.22 
+— 
+— 
+— 
+— 
+Non-productive 
+— 
+— 
+— 
+— 
+1 
+.40 
+Total 
+2 
+1.22 
+2 
+.23 
+3 
+.70 
+Exploration: 
+Oil 
+— 
+— 
+1 
+.15 
+— 
+— 
+Gas 
+2 
+.72 
+— 
+— 
+1 
+.22 
+Non-productive 
+5 
+1.24 
+1 
+.20 
+1 
+.50 
+Total 
+7 
+1.96 
+2 
+.35 
+2 
+.72 
+22
+Table of Contents 
+The following table sets forth our productive wells as of December 31, 2004:
+Wells 
+Gross 
+Net 
+Oil: 
+Working interest 
+46.00 
+4.06 
+Royalty interest 
+189.00 
+3.15 
+Total 
+235.00 
+7.21 
+Gas: 
+Working interest 
+39.00 
+17.34 
+Royalty interest 
+214.00 
+1.69 
+Total 
+253.00 
+19.03 
+A well is categorized as an oil well or a natural gas well based upon the ratio of oil to gas
+reserves on a Mcfe basis. However, some of our wells produce both oil and gas. At December 31,
+2004, we had no wells with multiple completions. At December 31, 2004, we had 1 gross (0.15 net)
+development oil well and 1 gross (0.22 net) exploration gas well in progress.
+Leasehold Acreage 
+The following table shows our approximate developed and undeveloped (gross and net) leasehold
+acreage as of December 31, 2004.
+Leasehold Acreage 
+Developed 
+Undeveloped 
+Location 
+Gross 
+Net 
+Gross 
+Net 
+Louisiana 
+6,060 
+3,952 
+5,386 
+3,173 
+Other states 
+— 
+— 
+681 
+509 
+Federal waters 
+96,743 
+66,400 
+266,380 
+70,802 
+Total 
+102,803 
+70,352 
+272,447 
+74,484 
+As of December 31, 2004, we owned various royalty and overriding royalty interests in 1,336 net
+developed and 6,862 net undeveloped acres. In addition, we owned 4,157 developed and 121,843
+undeveloped mineral acres.
+23
+Table of Contents 
+Major Customers 
+Our production is sold generally on month-to-month contracts at prevailing prices. The following
+table identifies customers to whom we sold a significant percentage of our total oil and gas
+production during each of the 12-month periods ended:
+December 31, 
+2004 
+2003 
+2002 
+Petrocom Energy Group, Ltd. 
+— 
+4 
+% 
+4 
+% 
+Dynegy 
+— 
+5 
+% 
+7 
+% 
+Prior Energy Corporation 
+— 
+20 
+% 
+— 
+Reliant Energy Services 
+6 
+% 
+28 
+% 
+70 
+% 
+Louis Dreyfus Energy Services 
+23 
+% 
+27 
+% 
+— 
+Shell Trading Company 
+30 
+% 
+— 
+— 
+Plains Marketing, L.P. 
+13 
+% 
+— 
+— 
+Conoco Phillips Company 
+8 
+% 
+— 
+— 
+Chevron Texaco Natural Gas 
+6 
+% 
+— 
+— 
+Because alternative purchasers of oil and gas are readily available, we believe that the loss of
+any of these purchasers would not result in a material adverse effect on our ability to market
+future oil and gas production.
+Title to Properties 
+We believe that the title to our oil and gas properties is good and defensible in accordance with
+standards generally accepted in the oil and gas industry, subject to such exceptions which, in our
+opinion, are not so material as to detract substantially from the use or value of such properties.
+Our properties are typically subject, in one degree or another, to one or more of the following:
+• 
+royalties and other burdens and obligations, express or implied, under oil and gas leases; 
+• 
+overriding royalties and other burdens created by us or our predecessors in title; 
+• 
+a variety of contractual obligations (including, in some cases, development obligations)
+arising under operating agreements, farmout agreements, production sales contracts and
+other agreements that may affect the properties or their titles; 
+• 
+back-ins and reversionary interests existing under purchase agreements and leasehold
+assignments; 
+• 
+liens that arise in the normal course of operations, such as those for unpaid taxes,
+statutory liens securing obligations to unpaid suppliers and contractors and contractual
+liens under operating agreements; 
+• 
+pooling, unitization and communitization agreements, declarations and orders; and 
+• 
+easements, restrictions, rights-of-way and other matters that commonly affect property. 
+To the extent that such burdens and obligations affect our rights to production revenues, they have
+been taken into account in calculating our net revenue interests and in estimating the size and
+value of our reserves. We believe that the burdens and obligations affecting our properties are
+conventional in the industry for properties of the kind owned by us.
+24
+Table of Contents 
+ITEM 3. LEGAL PROCEEDINGS 
+We are a defendant in various legal proceedings and claims, which arise in the ordinary course of
+our business. We do not believe the ultimate resolution of any such actions will have a material
+affect on our financial position or results of operations.
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 
+There were no matters submitted to a vote of security holders during the fourth quarter of 2004.
+25
+Table of Contents 
+PART II. 
+ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS 
+Our common stock trades on the New York Stock Exchange under the symbol “CPE”. The following table
+sets forth the high and low sale prices per share as reported for the periods indicated.
+Quarter Ended 
+High 
+Low 
+2003: 
+First quarter 
+$ 
+4.35 
+$ 
+3.35 
+Second quarter 
+8.44 
+3.66 
+Third quarter 
+7.95 
+5.46 
+Fourth quarter 
+11.48 
+7.31 
+2004: 
+First quarter 
+$ 
+11.23 
+$ 
+8.70 
+Second quarter 
+14.27 
+10.15 
+Third quarter 
+14.40 
+11.10 
+Fourth quarter 
+14.72 
+12.30 
+As of March 3, 2005, there were approximately 4,337 common stockholders of record.
+We have never paid dividends on our common stock and intend to retain our cash flow from
+operations, net of preferred stock dividends, for the future operation and development of our
+business. In addition, our primary credit facility and the terms of our outstanding subordinated
+debt prohibit the payment of cash dividends on our common stock.
+ITEM 6. SELECTED FINANCIAL DATA 
+The following table sets forth, as of the dates and for the periods indicated, selected financial
+information about us. The financial information for each of the five years in the period ended
+December 31, 2004 has been derived from our audited Consolidated Financial Statements for such
+periods. The information should be read in conjunction with “Management’s Discussion and Analysis
+of Financial Condition and Results of Operations” and the Consolidated Financial Statements and
+Notes thereto. The following information is not necessarily indicative of our future results.
+26
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+SELECTED HISTORICAL FINANCIAL INFORMATION 
+(In thousands, except per share amounts) 
+Years Ended December 31, 
+2004 
+2003 
+2002 
+2001 
+2000 
+Statement of Operations Data: 
+Operating revenues: 
+Oil and gas sales 
+$ 
+119,802 
+$ 
+73,697 
+$ 
+61,171 
+$ 
+60,010 
+$ 
+56,310 
+Operating expenses: 
+Lease operating expenses 
+22,308 
+11,301 
+11,030 
+11,252 
+9,339 
+Depreciation, depletion and amortization 
+47,453 
+28,253 
+27,096 
+21,081 
+17,153 
+General and administrative 
+8,758 
+4,713 
+4,705 
+4,635 
+4,155 
+Accretion expense 
+3,400 
+2,884 
+— 
+— 
+— 
+Derivative expense 
+1,371 
+535 
+708 
+— 
+— 
+Total operating expenses 
+83,290 
+47,686 
+43,539 
+36,968 
+30,647 
+Income (loss) from operations 
+36,512 
+26,011 
+17,632 
+23,042 
+25,663 
+Other (income) expenses: 
+Interest expense 
+20,137 
+30,614 
+26,140 
+12,805 
+8,420 
+Other (income) 
+(357 
+) 
+(444 
+) 
+(1,004 
+) 
+(1,742 
+) 
+(1,767 
+) 
+Loss on early extinguishment of debt 
+3,004 
+5,573 
+— 
+— 
+— 
+Gain on sale of pipeline 
+— 
+— 
+(2,454 
+) 
+— 
+— 
+Gain on sale of Enron derivatives 
+— 
+— 
+(2,479 
+) 
+— 
+— 
+Writedown of Enron derivatives 
+— 
+— 
+— 
+9,186 
+— 
+Total other (income) expenses 
+22,784 
+35,743 
+20,203 
+20,249 
+6,653 
+Income (loss) before income taxes 
+13,728 
+(9,732 
+) 
+(2,571 
+) 
+2,793 
+19,010 
+Income tax expense (benefit) 
+(6,697 
+) 
+8,432 
+(900 
+) 
+977 
+6,463 
+Income (loss) before Medusa Spar LLC and
+cumulative effect of change in accounting principle 
+20,425 
+(18,164 
+) 
+(1,671 
+) 
+1,816 
+12,547 
+Income (loss) on Medusa Spar LLC, net of tax 
+1,076 
+(8 
+) 
+— 
+— 
+— 
+Income (loss) before cumulative effect of change
+in accounting principle 
+21,501 
+(18,172 
+) 
+(1,671 
+) 
+1,816 
+12,547 
+Cumulative effect of change in accounting principle,
+net of tax 
+— 
+181 
+— 
+— 
+— 
+Net income (loss) 
+21,501 
+(17,991 
+) 
+(1,671 
+) 
+1,816 
+12,547 
+Preferred stock dividends 
+1,272 
+1,277 
+1,277 
+1,277 
+2,403 
+Net income (loss) available to common shares 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+$ 
+(2 ,948 
+) 
+$ 
+539 
+$ 
+10,144 
+27
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+SELECTED HISTORICAL FINANCIAL INFORMATION 
+(In thousands, except per share amounts) 
+Years Ended December 31, 
+2004 
+2003 
+2002 
+2001 
+2000 
+Net income (loss) available to common shares 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+$ 
+(2,948 
+) 
+$ 
+539 
+$ 
+10,144 
+Net income (loss) per common share: 
+Basic: 
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+1.28 
+$ 
+(1.42 
+) 
+$ 
+(.22 
+) 
+$ 
+.04 
+$ 
+.82 
+Cumulative effect of change in accounting principle,
+net of tax 
+— 
+.01 
+— 
+— 
+— 
+Net income (loss) available to common 
+$ 
+1.28 
+$ 
+(1.41 
+) 
+$ 
+(.22 
+) 
+$ 
+.04 
+$ 
+.82 
+Diluted: 
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+1.22 
+$ 
+(1.42 
+) 
+$ 
+(.22 
+) 
+$ 
+.04 
+$ 
+.80 
+Cumulative effect of change in accounting principle,
+net of tax 
+— 
+.01 
+— 
+— 
+— 
+Net income (loss) available to common 
+$ 
+1.22 
+$ 
+(1.41 
+) 
+$ 
+(.22 
+) 
+$ 
+.04 
+$ 
+.80 
+Shares used in computing net income (loss) per common share: 
+Basic 
+15,796 
+13,662 
+13,387 
+13,273 
+12,420 
+Diluted 
+17,678 
+13,662 
+13,387 
+13,366 
+12,745 
+Balance Sheet Data (end of period): 
+Oil and gas properties, net 
+$ 
+406,690 
+$ 
+390,163 
+$ 
+377,661 
+$ 
+343,158 
+$ 
+258,613 
+Total assets 
+$ 
+457,523 
+$ 
+496,032 
+$ 
+410,613 
+$ 
+372,095 
+$ 
+301,569 
+Long-term debt, less current portion 
+$ 
+192,351 
+$ 
+214,885 
+$ 
+248,269 
+$ 
+161,733 
+$ 
+134,000 
+Stockholders’ equity 
+$ 
+198,312 
+$ 
+133,261 
+$ 
+140,960 
+$ 
+147,224 
+$ 
+136,328 
+We use the full-cost method of accounting. Under this method of accounting, our net
+capitalized costs to acquire explore and develop oil and gas properties may not exceed the
+standardized measure of our proved reserves. If these capitalized costs exceed a ceiling amount,
+the excess is charged to expense.
+28
+Table of Contents 
+ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+The following discussion is intended to assist in an understanding of our financial condition and
+results of operations. Our Consolidated Financial Statements and Notes thereto contain detailed
+information that should be referred to in conjunction with the following discussion. See Item 8.
+“Financial Statements and Supplementary Data.”
+General 
+We have been engaged in the exploration, development, acquisition and production of oil and gas
+properties since 1950. Our revenues, profitability and future growth and the carrying value of our
+oil and gas properties are substantially dependent on prevailing prices of oil and gas and our
+ability to find, develop and acquire additional oil and gas reserves that are economically
+recoverable. Our ability to maintain or increase our borrowing capacity and to obtain additional
+capital on attractive terms is also influenced by oil and gas prices.
+Significant events of our financial and operating results for the year ended December 31, 2004
+included:
+• 
+an increase in 2004 production and revenues of 57% and 63%, respectively, over 2003
+levels; 
+• 
+borrowing an additional $15 million for a term of seven years at an interest rate of
+9.75% pursuant to a senior unsecured credit agreement; 
+• 
+closing a three-year senior secured credit facility with an initial borrowing base of
+$60 million which can be increased to a maximum of $175 million; 
+• 
+closing the public offering of 3,450,000 shares of common stock priced at $13.25 per
+share raising net proceeds of approximately $44 million, after expenses; 
+• 
+sub-debt redemptions and bank line paydown; and 
+• 
+an income tax benefit of $6.7 million as the result of reversing a valuation allowance
+which was established in 2003 against our deferred tax assets. See Note 3 to the Company’s Consolidated Financial
+Statements for a more detailed discussion. 
+The additional borrowing pursuant to our 9.75% senior unsecured credit agreement and the public
+offering of shares of our common stock allowed us to redeem $33 million of senior subordinated
+notes which were maturing in 2005, redeem $10 million of 12% loans maturing in March 2005 and
+reduce the outstanding balance under our senior secured credit facility. In addition, excess funds
+were used for general corporate purposes. As a result, we expect that planned 2005 capital
+expenditures of approximately $80 million will be funded with cash flows from operations. The
+current borrowing base is $60 million under the senior secured credit facility and $52.7 million
+was available on December 31, 2004. For a more detailed discussion of outstanding debt see Note 5
+to our Consolidated Financial Statements.
+Our estimated net proved oil and gas reserves decreased at December 31, 2004 to 191 Bcfe. This
+represents a decrease of 12% from previous year-end 2003 estimated proved reserves of 217 Bcfe.
+29
+Table of Contents 
+Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in
+the supply of and demand for oil and gas, market uncertainty and a variety of additional factors
+beyond our control. These factors include weather conditions in the United States, the condition
+of the United States economy, the actions of the Organization of Petroleum Exporting Countries,
+governmental regulation, political stability in the Middle East and elsewhere, the foreign supply
+of crude oil and natural gas, the price of foreign imports and the availability of alternate fuel
+sources. Any substantial and extended decline in the price of crude oil or natural gas would have
+an adverse effect on our carrying value of our proved reserves, borrowing capacity, revenues,
+profitability and cash flows from operations. We use derivative financial instruments (see Note 6
+to our Consolidated Financial Statements and Item 7A. “Quantitative and Qualitative Disclosures
+About Market Risks”) for price protection purposes on a limited amount of our future production and
+do not use them for trading purposes. On a Mcfe basis, natural gas represents 43% of the budgeted
+2005 production and 38% of proved reserves at year-end 2004.
+Inflation has not had a material impact on us and is not expected to have a material impact on us
+in the future.
+Summary of Significant Accounting Policies 
+On December 16, 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised
+2004), (“SFAS 123R”) Share-Based Payment, which is a revision of Statement of Financial Accounting
+Standards No. 123, (“SFAS 123”) Accounting for Stock-Based Compensation . SFAS 123R supersedes APB
+Opinion No. 25, Accounting for Stock Issued to Employees , and amends Statement of Financial
+Accounting Standards No. 95, Statement of Cash Flows . Generally, the approach in SFAS 123R is
+similar to the approach described in SFAS 123. However, SFAS 123R requires all share-based
+payments to employees, including grants of employee stock options, to be recognized in the income
+statement based on their fair values. Pro forma disclosure is no longer an alternative.
+SFAS 123R must be adopted no later than July 1, 2005. Early adoption will be permitted in periods
+in which financial statements have not yet been issued.
+SFAS 123R permits public companies to adopt its requirements
+using one of two methods below:
+• 
+A “modified prospective” method in which compensation cost is recognized beginning with the effective date (a) based on the requirements of SFAS 123R
+for all share-based payments granted after the effective date and (b) based on the requirements of SFAS 123 for all awards granted to employees
+prior to the effective date of SFAS 123R that remain unvested on the effective date; or 
+• 
+A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to
+restate based on the amounts previously recognized under SFAS 123 for purposes of pro forma disclosures either (a) all prior periods presented or (b)
+prior interim periods of the year of adoption. 
+We expect to adopt SFAS 123R
+on July 1, 2005 using the modified prospective method.
+As permitted by SFAS 123, we currently accounts for share-based payments to employees
+using Opinion 25’s intrinsic value method and, as such, generally recognizes no compensation cost
+for employee stock options. Accordingly, the adoption of SFAS 123R’s fair value method will have a
+significant impact on our result of operations, although it will have no impact on our overall
+financial position. The impact of adoption of SFAS 123R cannot be predicted at this time because
+it will depend on levels of share-based payments granted in the future. However, had we adopted
+SFAS 123R in prior periods, the impact of that standard would have approximated the impact of SFAS
+123 as described in the disclosure of pro forma net income and earnings per share in Note 2 to our
+consolidated financial statements.
+In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest
+Entities, an Interpretation of Accounting Research Bulletin (ARB) 51” (“FIN 46”). FIN 46 addresses
+consolidation by business enterprises of variable interest entities (“VIEs”). We adopted FIN 46,
+as revised, as of December 31, 2003, which had no impact on our results of operations or financial
+position.
+In September 2004, the SEC issued Staff Accounting Bulletin (“SAB”) No. 106 which expressed the
+Staff’s views regarding the application of Statement of Financial Accounting Standards (“SFAS”) No.
+143 “Accounting for Asset Retirement Obligations” by oil and gas producing companies following
+full-cost accounting method. SAB No. 106 specifies that subsequent to the adoption of SFAS No. 143
+an oil and gas
+30
+Table of Contents 
+company following the full-cost method of accounting should include assets recorded
+in connection with the recognition of an asset retirement obligation pursuant to SFAS No. 143 as
+part of the costs subject to the full -cost ceiling limitation. The future cash outflows
+associated with settling the recorded asset retirement obligations should be excluded from the
+computation of the present value of estimated future net revenues used in applying the ceiling
+test. The Company will be required to adopt the provisions of SAB No. 106 prospectively in the
+first quarter of 2005 which will have no impact on our results of operations or financial position.
+Property and Equipment. We follow the full-cost method of accounting for oil and gas properties
+whereby all costs incurred in connection with the acquisition, exploration and development of oil
+and gas reserves, including certain overhead costs, are capitalized into the “full-cost pool.” The
+amounts we capitalize into the full-cost pool are depleted (charged against earnings) using the
+unit-of-production method. The full-cost method of accounting for our proved oil and gas
+properties requires that we make estimates based on assumptions as to future events which could
+change. These estimates are described below.
+Depreciation, Depletion and Amortization (DD&A) of Oil and Gas Properties . We calculate depletion
+by using the capitalized costs in our full-cost pool plus future development and abandonment costs
+(combined, the depletable base) and our estimated net proved reserve quantities. Capitalized
+costs added to the full-cost pool and other costs added to the depletable base include the
+following:
+• 
+the cost of drilling and equipping productive wells, dry hole costs, acquisition costs
+of properties with proved reserves, delay rentals and other costs related to exploration
+and development of our oil and gas properties; 
+• 
+our payroll and general and administrative costs and costs related to fringe benefits
+paid to employees directly engaged in the acquisition, exploration and/or development of
+oil and gas properties as well as other directly identifiable general and administrative
+costs associated with such activities. Such capitalized costs do not include any costs
+related to our production of oil and gas or our general corporate overhead; 
+• 
+costs associated with properties that do not have proved reserves attributed to them are
+excluded from the full-cost pool. These unevaluated property costs are added to the
+full-cost pool at such time as wells are completed on the properties, the properties are
+sold or we determine these costs have been impaired. Our determination that a property has
+or has not been impaired (which is discussed below) requires that we make assumptions about
+future events; 
+• 
+our estimates of future costs to develop proved properties are added to the full-cost
+pool for purposes of the DD&A computation. We use assumptions based on the latest
+geologic, engineering, regulatory and cost data available to us to estimate these amounts.
+However, the estimates we make are subjective and may change over time. Our estimates of
+future development costs are periodically updated as additional information becomes
+available; and 
+• 
+prior to the adoption of SFAS 143, estimated costs to dismantle, abandon and restore a
+proved property were added to the full-cost pool for the purposes of DD&A. Subsequent to
+the adoption of SFAS 143, effective January 1, 2003, these costs are included in the
+full-cost pool. Such cost estimates are periodically updated as additional information
+becomes available. As discussed below, specifically SFAS
+143, beginning January 1, 2003, we changed the method for which we account for such costs. 
+Capitalized costs included in the full-cost pool are depleted and charged against earnings using
+the unit of production method. Under this method, we estimate our quantity of proved reserves at
+the beginning of each accounting period. For each barrel of oil equivalent produced during the
+period, we record a depletion
+31
+Table of Contents 
+charge equal to the amount included in the depletable base (net of
+accumulated depreciation, depletion and amortization) divided by our estimated net proved reserve
+quantities.
+Because we use estimates and assumptions to calculate proved reserves (as discussed below) and the
+amounts included in the full-cost pool, our depletion calculations will change if the estimates and
+assumptions are not realized. Such changes may be material.
+Ceiling Test . Under the full-cost accounting rules, capitalized costs included in the full-cost
+pool, net of accumulated depreciation, depletion and amortization (DD&A), cost of unevaluated
+properties and deferred income taxes, may not exceed the present value of our estimated future net
+cash flows from proved oil and gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties
+included in the costs being amortized, net of related tax effects. These rules generally require
+that, in estimating future net cash flow, we assume that future oil and gas production will be sold
+at the unescalated market price for oil and gas received at the end of each fiscal quarter and that
+future costs to produce oil and gas will remain constant at the prices in effect at the end of the
+fiscal quarter. We are required to write-down and charge to earnings the amount, if any, by which
+these costs exceed the discounted future net cash flows, unless prices recover sufficiently before
+the date of our financial statements. Given the volatility of oil and gas prices, it is likely
+that our estimates of discounted future net cash flows from proved oil and gas reserves will change
+in the near term. If oil and gas prices decline significantly, even if only for a short period of
+time, it is possible that writedowns of oil and gas properties could occur in the future.
+Estimating Reserves and Present Values . Our estimates of quantities of proved oil and gas reserves
+and the discounted present value of such reserves at the end of each quarter are based on numerous
+assumptions which are likely to change over time. These assumptions include:
+• 
+the prices at which we can sell our oil and gas production in the future. Oil and gas
+prices are volatile, but we are generally required to assume that they will not change from
+the prices in effect at the end of the quarter. In general, higher oil and gas prices will
+increase quantities of proved reserves and the present value of such reserves, while lower
+prices will decrease these amounts. Because our properties have relatively short
+productive lives, changes in prices will affect the present value more than quantities of
+oil and gas reserves; 
+• 
+the costs to develop and produce our reserves and the costs to dismantle our production
+facilities when reserves are depleted. These costs are likely to change over time, but we
+are required to assume that costs in effect at the end of the quarter will not change.
+Increases in costs will reduce oil and gas quantities and present values, while decreases
+in costs will increase such amounts. Because our properties have relatively short
+productive lives, changes in costs will affect the present value more than quantities of
+oil and gas reserves; and 
+• 
+the liability to pay royalties to the Mineral Management Service. See Note 7 of our
+Consolidated Financial Statements for a more detailed discussion of this potential
+liability. 
+In addition, the process of estimating proved oil and gas reserves requires that our independent
+and internal reserve engineers exercise judgment based on available geological, geophysical and
+technical information. We have described the risks associated with reserve estimation and the
+volatility of oil and gas prices, under “Risk Factors”.
+Unproved Properties . Costs associated with properties that do not have proved reserves, including
+capitalized interest, are excluded from the full-cost pool. These unproved properties are included
+in the line
+32
+Table of Contents 
+item “Unevaluated properties excluded from amortization.” Unproved property costs are
+transferred to the full-cost pool when wells are completed on the properties or the properties are
+sold. In addition, we are required to determine whether our unproved properties are impaired and,
+if so, add the costs of such properties to the full-cost pool. We determine whether an unproved
+property should be impaired by periodically reviewing our exploration program on a property by
+property basis. This determination may require the exercise of substantial judgment by our
+management.
+Asset Retirement Obligations. In June 2001, the FASB issued Statement of Financial Accounting
+Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”) effective for fiscal
+years beginning after June 15, 2002. SFAS 143 essentially requires entities to record the fair
+value of a liability for obligations associated with the retirement of tangible long-lived assets
+and the associated asset retirement costs. We adopted the statement on January 1, 2003 resulting in a cumulative effect of
+accounting change of $181,000, net of tax. See Note 8 to our Consolidated Financial Statements.
+Derivatives. We use derivative financial instruments for price protection purposes on a limited
+amount of our future production and do not use them for trading purposes. Such derivatives were
+accounted for in years prior to 2001 as hedges and have been recognized as an adjustment to oil and
+gas sales in the period in which they are related. We currently use the accounting treatment for
+derivatives specified under SFAS 133. 
+See Note 6 to our Consolidated Financial Statements.
+Income Taxes. We follow the asset and liability method of accounting for deferred income taxes
+prescribed by Statement of Financial Accounting Standards No. 109 (“SFAS 109”) “Accounting for
+Income Taxes”. The statement provides for the recognition of a deferred tax asset for deductible
+temporary timing differences, capital and operating loss carryforwards, statutory depletion
+carryforward and tax credit carryforwards, net of a “valuation allowance”. The valuation allowance
+is provided for that portion of the asset, for which it is deemed more likely than not, that it
+will not be realized.
+SFAS 109 provides for the weighing of positive and negative evidence in determining whether it is
+more likely than not that a deferred tax asset is recoverable. We incurred losses in 2002 and 2003
+and had losses on an aggregate basis for the three-year period ended December 31, 2003. Because of
+these cumulative losses we established a full valuation allowance of $11.5 million as of December
+31, 2003.
+As a result of production from our first two deepwater projects starting in November 2003, as well
+as refinancing our highest cost debt in 2004, we achieved profitable operations and have income on
+an aggregate basis for the three-year period ended December 31, 2004. We also expect 2005
+production levels to exceed 2004 levels and expect to utilize most if not all of the deferred tax
+asset in 2005. As a result, we have reversed the valuation allowance which had a balance of $7.0
+million as of December 31, 2004. See Note 3 to the Consolidated Financial Statements for further
+disclosure.
+33
+Table of Contents 
+Liquidity and Capital Resources 
+Our primary sources of capital are cash flows from operations, borrowings from financial
+institutions and the sale of debt and equity securities. Net cash and cash equivalents decreased
+during 2004 to $3.3 million, down $5.4 million. Cash provided from operating activities during
+2004 totaled $70.9 million, up 106% from $34.6 million in 2003. Dividends paid on preferred stock
+were $1.3 million. All of our outstanding debt was restructured during December 2003 and the first
+half of 2004. The restructuring is discussed in the following paragraphs.
+In December 2003 we borrowed $185 million pursuant to a senior unsecured credit facility with a
+stated interest rate of 9.75%. In conjunction with the new senior unsecured notes, we issued
+detachable warrants to purchase 2.775 million shares of our common stock at an exercise price of
+$10 per share and an expiration date in December 2010. This senior unsecured debt matures December 8, 2010. The net proceeds from the loans of $181.3 million were
+used to redeem $22.9 million of 10.125% senior subordinated notes due July 31, 2004 (“10.125%
+notes”), $40 million of 10.25% senior subordinated notes due September 15, 2004 (“10.25% notes”),
+$85 million of our 12% loans due March 31, 2005 (“12% loans”) plus a 1% call premium of $850,000
+and to reduce the balance outstanding under our senior secured revolving credit facility. A charge
+of $5.6 million was incurred in 2003 and a charge of approximately $1.9 million was incurred in
+2004 as a result of the early extinguishment of debt. We exercised covenant defeasance under the
+indentures for the 10.125% and 10.25% notes on December 8, 2003 and distributed a required 30-day
+redemption notice. The funds necessary to redeem the notes were placed in trust and the trustee
+paid the holders of the notes on January 8, 2004. The funds in trust were classified on our
+December 31, 2003 balance sheet as restricted cash.
+During March 2004, we borrowed an additional $15 million under our 9.75% senior unsecured credit
+facility bringing the total outstanding to $200 million. The net proceeds of approximately $14
+million were primarily used to retire the remaining $10 million of 12% loans plus a 1% call premium
+of $100,000. A charge of $559,000 was incurred as a result of early extinguishment of debt.
+In March 2004, the $200 million in aggregate principal amount of loans outstanding under the 9.75%
+senior unsecured credit facility were exchanged for 9.75% Senior Notes due 2010, Series A, “Series
+A notes”, issued pursuant to a senior indenture between us and American Stock Transfer & Trust
+Company dated March 15, 2004. On August 12, 2004, we completed an offer to exchange our 9.75%
+Senior Notes due 2010, Series B, that have been registered under the Securities Act of 1933, for
+all outstanding Series A notes. See Note 5 of our Consolidated Financial Statements for a more
+detailed description of these notes.
+On June 15, 2004, we closed on a three-year senior secured credit facility underwritten by Union
+Bank of California, N.A. The credit facility includes an initial borrowing base, determined by the
+lender, of $60 million, which may be adjusted semi-annually and could increase to a maximum of $175
+million. At closing, $21 million was advanced under the new facility for repayment of the existing
+debt under the expiring credit facility with Wachovia Bank, National Association. As of December
+31, 2004 there was $5.0 million outstanding under the facility and we had an aggregate of $2.3
+million in outstanding letters of credit issued under the credit facility. These letters of credit
+secure obligations under the outstanding hedging contracts described in Note 6 to the Consolidated
+Financial Statements. The outstanding letters of credit reduce the amount available for borrowings
+under the credit facility. As a result, $52.7 million was available for future borrowings under
+the credit facility as of December 31, 2004.
+34
+Table of Contents 
+On June 22, 2004, we closed the public offering of three million shares of common stock priced at
+$13.25 per share raising net proceeds of approximately $38.2 million, after expenses. In addition,
+we granted the underwriter, Johnson Rice & Company L.L.C., an over-allotment option to purchase an
+additional 450,000 shares. On June 30, 2004, the underwriter exercised the over-allotment option
+for an additional 450,000 shares priced at $13.25 per share, raising the net proceeds of the
+offering by approximately $5.7 million, after expenses. The proceeds from the transactions were
+used to redeem $33 million of our 11% Senior Subordinated Notes due December 15, 2005 to reduce the
+balance outstanding under our senior secured credit facility and general corporate purposes.
+Outstanding debt on
+December 31, 2004 was $192.9 million compared to $308.1 million on December 31,
+2003. Restricted cash in the amount of
+$62.9 million was used to payoff 2004 Senior Subordinated Notes
+on January 8, 2004 which were included in outstanding debt on
+December 31, 2003. The senior secured credit
+facility and our senior notes contain various covenants including restrictions on additional
+indebtedness and payment of cash dividends as well as maintenance of certain financial ratios. We
+were in compliance with these covenants at December 31, 2004.
+In December 2003, we announced the formation of a limited liability company, Medusa Spar LLC, which
+now owns a 75% undivided ownership interest in the deepwater spar production facilities on our
+Medusa Field in the Gulf of Mexico. We contributed a 15% undivided ownership interest in the
+production facility to the LLC in return for approximately $25 million in cash and a 10% ownership
+interest in the LLC. Our cash proceeds were used to reduce the balance outstanding under our senior
+secured credit facility. The LLC will earn a tariff based upon production volume throughput from
+the Medusa area. We are obligated to process our share of production from the Medusa Field and any
+future discoveries in the area through the spar production facilities. The LLC used the cash
+proceeds from $83.7 million of non-recourse financing and a cash contribution by one of the LLC
+owners to acquire its 75% interest in the spar. On December 31, 2004, $64.1 million of this
+financing was outstanding. The balance of the LLC is owned by Oceaneering International, Inc.
+(NYSE:OII) and Murphy Oil Corporation (NYSE:MUR). We are accounting for our 10% ownership interest
+in the LLC under the equity method.
+Our planned capital expenditures for 2005 total $80 million. We anticipate that cash flow
+generated during 2005 will fund these expenditures and the current portion of our asset retirement
+obligation in the amount of $13.3 million. Availability under our senior secured credit facility
+will also be available if necessary. Capitalized interest and general and administrative expenses
+are included in the $80 million. 
+Capital expenditure plans for 2005 include:
+• 
+the completion and development of two 2004 shelf discoveries; 
+• 
+the non-discretionary drilling of approximately 13 deep shelf and onshore exploratory
+wells we developed using our 3-D seismic and AVO technology; 
+• 
+drilling of a development well on our deepwater Entrada discovery; 
+• 
+drilling of two deepwater Medusa satellite prospects and one deepwater exploratory well; 
+• 
+lease and seismic acquisition; and 
+• 
+capitalized interest and overhead. 
+35
+Table of Contents 
+The following table describes our outstanding contractual obligations (in thousands) as of December
+31, 2004:
+Contractual 
+Less Than 
+One-Three 
+Four-Five 
+After-Five 
+Obligations 
+Total 
+One Year 
+Years 
+Years 
+Years 
+Senior Secured Credit Facility 
+$ 
+5,000 
+$ 
+— 
+$ 
+5,000 
+$ 
+— 
+$ 
+— 
+9.75% Senior Notes 
+200,000 
+— 
+— 
+— 
+200,000 
+Capital lease (future minimum payments) 
+2,531 
+822 
+787 
+457 
+465 
+Throughput Commitments: 
+Medusa Spar, LLC 
+17,508 
+4,824 
+6,988 
+5,696 
+— 
+Medusa Oil Pipeline 
+860 
+254 
+311 
+132 
+163 
+Hurricane Ivan 
+On September 13, 2004, several of our fields were shut-in due to Hurricane Ivan. Two of our major
+fields, Medusa which is located in Mississippi Canyon Blocks 538 and 582 and Mobile Bay Blocks 952,
+953 and 955, incurred damage as a result of the hurricane.
+The Medusa spar production facility incurred minor damage, but a platform work-over rig owned by a
+third party incurred significant damage and had to be removed from the Medusa spar production
+facility. After debris clean up and repairs, partial production was restored on October 13, 2004
+and pre-hurricane production levels were achieved by October 22, 2004.
+Mobile Bay Blocks 952, 953 and 955 incurred minor damage and wells were brought on-line as repairs
+were completed. Partial production was restored on September 24, 2004 and the field reached
+pre-hurricane production levels by October 17, 2004.
+Production from Medusa and Mobile Bay Blocks 952, 953 and 955 represented approximately 60% of our
+production for the eight months ended August 31, 2004.
+36
+Table of Contents 
+Results of Operations 
+The following table sets forth certain operating information with respect to our oil and gas
+operations for each of the three years in the period ended December 31, 2004.
+December 31, 
+2004 
+2003 
+2002(b) 
+Production: 
+Oil (MBbls) 
+1,736 
+268 
+226 
+Gas (MMcf) 
+11,387 
+12,315 
+14,215 
+Total production (MMcfe) 
+21,801 
+13,923 
+15,571 
+Average daily production (MMcfe) 
+59.6 
+38.1 
+42.7 
+Average sales price (a): 
+Oil (per Bbl) 
+$ 
+28.71 
+$ 
+28.72 
+$ 
+23.11 
+Gas (per Mcf) 
+$ 
+6.15 
+$ 
+5.36 
+$ 
+3.94 
+Total (per Mcfe) 
+$ 
+5.50 
+$ 
+5.29 
+$ 
+3.93 
+Oil and Gas revenues (in thousands): 
+Gas revenue 
+$ 
+69,976 
+$ 
+66,001 
+$ 
+55,949 
+Oil revenue 
+49,826 
+7,696 
+5,222 
+Total 
+$ 
+119,802 
+$ 
+73,697 
+$ 
+61,171 
+Oil and gas production costs (in thousands): 
+Lease operating expenses 
+$ 
+22,308 
+$ 
+11,301 
+$ 
+11,030 
+Additional per Mcfe data: 
+Sales price 
+$ 
+5.50 
+$ 
+5.29 
+$ 
+3.93 
+Lease operating expenses 
+1.02 
+.81 
+.71 
+Operating margin 
+$ 
+4.48 
+$ 
+4.48 
+$ 
+3.22 
+Depletion 
+$ 
+2.18 
+$ 
+2.03 
+$ 
+1.73 
+Accretion 
+$ 
+.16 
+$ 
+.21 
+$ 
+— 
+General and administrative (net of management fees) 
+$ 
+.40 
+$ 
+.34 
+$ 
+.30 
+(a) 
+Average sales price includes hedging gains and losses. 
+(b) 
+Production volumes include 1,200 MMcf for the year 2002 at an average price of $2.08 per Mcf
+associated with a volumetric production payment. 
+37
+Table of Contents 
+Off-Balance Sheet Arrangements 
+In December 2003, we announced the formation of a limited liability company, Medusa Spar LLC, which
+now owns a 75% undivided ownership interest in the deepwater spar production facilities on our
+Medusa Field in the Gulf of Mexico. We contributed a 15% undivided ownership interest in the
+production facility to Medusa Spar LLC in return for approximately $25 million in cash and a 10%
+ownership interest in the LLC. The LLC will earn a tariff based upon production volume throughput
+from the Medusa area. We are obligated to process our share of production from the Medusa Field and
+any future discoveries in the area through the spar production facilities. This arrangement allows
+us to defer the cost of the spar production facility over the life of the Medusa Field. Our cash
+proceeds were used to reduce the balance outstanding under our senior secured credit facility. The
+LLC used the cash proceeds from $83.7 million of non-recourse financing and a cash contribution by
+one of the LLC owners to acquire its 75% interest in the spar. On December 31, 2004, $64.1 million
+of the financing was outstanding. The balance of Medusa Spar LLC is owned by Oceaneering
+International, Inc. (NYSE:OII) and Murphy Oil Corporation (NYSE:MUR). We are accounting for our
+10% ownership interest in the LLC under the equity method.
+Comparison of Results of Operations for the Years Ended December 31, 2004 and 2003 
+Oil and Gas Revenues 
+Total production for 2004 increased by 57% versus 2003 and total oil and gas revenues increased 63%
+from $73.7 million in 2003 to $119.8 million in 2004. Increased production was primarily due to our
+deepwater discoveries, Medusa and Habanero, which began producing late in the fourth quarter of
+2003.
+Gas production during 2004 totaled 11.4 Bcf and generated $70.0 million in revenues compared to
+12.3 Bcf and $66.0 million in revenues during the same period in 2003. Average gas prices realized
+for 2004 were $6.15 per Mcf compared to $5.36 per Mcf during the same period last year. The
+decrease in production was primarily due to downtime for Hurricane Ivan and the normal and expected
+decline in production from our Mobile area fields and older properties. These factors were
+partially offset by production from Medusa and Habanero.
+Oil production during 2004 totaled 1,736,000 barrels and generated $49.8 million in revenues
+compared to 268,000 barrels and $7.7 million in revenues for the same period in 2003. Average oil
+prices realized in 2004 were $28.71 per barrel compared to $28.72 per barrel in 2003. The increase
+in production was due to the initial production from our deepwater discoveries, Medusa and
+Habanero, which began producing late in the fourth quarter of 2003. The production increase was
+offset slightly by downtime for Hurricane Ivan and normal and expected declines in production from
+older properties.
+Lease Operating Expenses 
+Lease operating expenses for 2004 increased by 97% to $22.3 million compared to $11.3 million for
+the same period in 2003. The increase was primarily due to lease operating expenses related to our
+deepwater discoveries, Medusa and Habanero, which began producing late in the fourth quarter of
+2003.
+Depreciation, Depletion and Amortization 
+Depreciation, depletion and amortization for 2004 and 2003 were $47.5 million and $28.3 million,
+respectively. The 68% increase was primarily due to higher production volumes for 2004 compared to
+2003.
+38
+Table of Contents 
+Accretion Expense 
+Accretion expense for 2004 and 2003 of $3.4 million and $2.9 million, respectively, represents
+accretion for our asset retirement obligations. The increase was due to the addition of plugging
+and abandonment obligations. See Note 8 to the Consolidated Financial Statements.
+General and Administrative 
+General and administrative expenses for 2004, net of amounts capitalized, were $8.8 million
+compared to $4.7 million incurred in 2003. There was a charge in general and administrative
+expenses of $2.6 million in the first quarter of 2004 for the early retirement of two executive
+officers of the Company. Also reduced capitalized overhead, higher
+directors’ fees, and increased independent and internal audit
+costs resulting from implementation of Sarbanes – Oxley 404 contributed to the increase in general and administrative
+expenses.
+Interest Expense 
+Interest expense decreased by 34% in 2004 to $20.1 million compared to $30.6 million in 2003. This
+is a result of lower debt levels and lower interest rates due to the restructuring of debt in
+December 2003 and during the six-month period ended June 30, 2004 in additional to an equity offering completed in
+the second quarter of 2004. In addition, amortization of deferred financing costs and bond
+discounts decreased due to the write-off of unamortized deferred financing costs and bond discounts
+associated with the early extinguishment of debt.
+Loss on Early Extinguishment of Debt 
+A loss of $3.0 million and $5.6 million was incurred in 2004 and 2003, respectively. Both were
+incurred for the write-off of deferred financing costs, pre-payment premiums and bond discounts
+associated with the early extinguishment of debt.
+Income Taxes 
+The income tax benefit of $6.7 million in 2004 resulted primarily from the reversal of the
+valuation allowance established in 2003 against our deferred tax asset. As a result of production
+from our first two deepwater projects starting in November 2003, as well as refinancing its highest cost debt in 2004, we
+achieved profitable operations and have income on an aggregate basis for the three-year period ended December 31, 2004. Callon also expects 2005 production levels
+to exceed 2004 levels and expects to utilize most if not all of the deferred tax asset in 2005. As a result, we reversed the valuation allowance.
+See Note 3 to our Consolidated Financial Statements for a more detailed discussion.
+Comparison of Results of Operations for the Years Ended December 31, 2003 and 2002 
+Oil and Gas Revenues 
+Total oil and gas revenues increased 20% from $61.2 million in 2002 to $73.7 million in 2003 while
+total production for 2003 decreased by 11% versus 2002. Realized oil and gas prices were
+substantially higher when compared to the same period in 2002 and accounted for the increase in
+revenue. Gas revenues for 2002 included $9.2 million of non-cash revenue related to the Enron
+derivatives discussed in Note 6 to the Consolidated Financial Statements.
+Gas production during 2003 totaled 12.3 Bcf and generated $66.0 million in revenues compared to
+14.2 Bcf and $55.9 million in revenues during the same period in 2002. Average gas prices for 2003
+were $5.36 per Mcf compared to $3.94 per Mcf during the same period in 2002. The decrease in
+production was primarily
+39
+Table of Contents 
+due to the depletion of the lowest productive zone of the East Cameron
+Block 294 field. The well at East Cameron Block 294 was returned to production after a
+recompletion to a behind pipe zone in the third quarter of 2003. Also, the sale of the North and
+Northwest Dauphin Island fields in the fourth quarter of 2002 and the normal and expected declines
+in production from other properties contributed to the variance.
+Oil production during 2003 totaled 268,000 barrels and generated $7.7 million in revenues compared
+to 226,000 barrels and $5.2 million in revenues for the same period in 2002. Average oil prices
+received in 2003 were $28.72 per barrel compared to $23.11 per barrel in 2002. The increase in
+production was due to the initial production from our deepwater discoveries, Medusa and Habanero,
+which began producing late in the fourth quarter of 2003. This was offset slightly by downtime for
+maintenance to the facility and equipment at the Big Escambia Creek Field formally operated by
+ExxonMobil Corporation, currently operated by Vintage, and normal and expected declines in
+production from older properties.
+Lease Operating Expenses 
+Lease operating expenses for 2003 increased by 2% to $11.3 million compared to $11.0 million for
+the same period in 2002. The increase was primarily due to the increase in lease operating
+expenses for the Mobile Block 864 area resulting from the implementation of the accelerated
+production program in the second quarter of 2002 and lease operating expenses related to our
+deepwater discoveries, Medusa and Habanero, which began producing late in the fourth quarter of
+2003. The increase was slightly offset as a result of the
+sale of North and Northwest Dauphin Island fields in the fourth quarter of 2002 which reduced lease
+operating expenses for 2003.
+Depreciation, Depletion and Amortization 
+Depreciation, depletion and amortization for 2003 and 2002 were $28.3 million and $27.1 million,
+respectively. The 4% increase was due primarily to the downward reserve revisions for our
+Boomslang Field at Ewing Bank Block 994 at the end of 2002. This decrease in estimated proved
+reserves increased the depletable cost per unit of production.
+Accretion Expense 
+Accretion expense of $2.9 million represents accretion for our asset retirement obligations for
+2003.
+General and Administrative 
+General and administrative expenses for 2003, net of amounts capitalized, were $4.7 million and
+flat with the amount incurred in 2002.
+Interest Expense 
+Interest expense increased by 17% in 2003 to $30.6 million compared to $26.1 million in 2002. This
+was a result of higher debt levels.
+40
+Table of Contents 
+Loss on Early Extinguishment of Debt 
+A loss of $5.6 million was incurred in December of 2003 for the write-off of deferred financing
+costs and bond discounts associated with the early extinguishment of $85 million of the 12% loans
+due in 2005 plus a 1% pre-payment premium.
+Income Taxes 
+The income tax expense of $8.4 million in 2003 was primarily due to a charge of $11.5 million to
+establish a valuation allowance against our deferred tax asset.
+We incurred losses in 2002 and 2003 and had losses on an
+aggregate basis for the three-year period ended December 31, 2003.
+Because of these cumulative losses we established a full valuation allowance.
+See Note 3
+to our Consolidated Financial Statements for a more detailed discussion.
+41
+Table of Contents 
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS 
+The Company’s revenues are derived from the sale of its crude oil and natural gas production. In
+recent months, the prices for oil and gas have increased; however, they remain extremely volatile
+and sometimes experience large fluctuations as a result of relatively small changes in supplies,
+weather conditions, economic conditions and government actions. The Company enters into derivative
+financial instruments to hedge oil and gas price risks for the production volumes to which the
+hedge relates. The derivatives reduce the Company’s exposure on the hedged volumes to decreases in
+commodity prices and limit the benefit the Company might otherwise have received from any increases
+in commodity prices on the hedged volumes.
+The Company also enters into price “collars” to reduce the risk of changes in oil and gas prices.
+Under these arrangements, no payments are due by either party so long as the market price is above
+the floor price set in the collar and below the ceiling. If the price falls below the floor, the
+counter-party to the collar pays the difference to the Company and if the price is above the
+ceiling, the counter-party receives the difference from the Company. Another type of hedging
+contract Callon has entered into is a put contract. Under a put, if the price falls below the set
+floor price, the counter-party to the contract pays the difference to the Company. The Company
+enters into these various agreements to reduce the effects of volatile oil and gas prices and does
+not enter into hedge transactions for speculative purposes. See Note 6 to the Consolidated
+Financial Statements for a description of the Company’s hedged position at December
+31, 2004. There have been no significant changes in market risks faced by the Company since the
+end of 2004.
+Based on projected annual sales volumes for 2005 (excluding forecast production increases over
+2004), a 10% decline in the prices Callon receives for its crude oil and natural gas production
+would have an approximate $13.3 million impact on our revenues.
+42
+Table of Contents 
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+Page 
+Report of Independent Registered Public Accounting Firm 
+44 
+Consolidated Balance Sheets as of December 31, 2004
+and 2003 
+45 
+Consolidated Statements of Operations for Each of the Three Years
+in the Period Ended December 31, 2004 
+46 
+Consolidated Statements of Stockholders’ Equity
+for Each of the Three Years in the Period Ended December 31, 2004 
+47 
+Consolidated Statements of Cash Flows for Each of the Three Years
+in the Period Ended December 31, 2004 
+48 
+Notes to Consolidated Financial Statements 
+49 
+43
+Table of Contents 
+Report of Independent Registered Public Accounting Firm
+The Stockholders and Board of Directors 
+Callon Petroleum Company
+We have audited the accompanying consolidated balance sheets of Callon Petroleum Company as of
+December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’
+equity and cash flows for each of the three years in the period ended December 31, 2004. These
+financial statements are the responsibility of the Company’s management. Our responsibility is to
+express an opinion on these financial statements based on our audits.
+We conducted our audits in accordance with the standards of the Public Company Accounting
+Oversight Board (United States). Those standards require that we plan and perform the audit to
+obtain reasonable assurance about whether the financial statements are free of material
+misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
+disclosures in the financial statements. An audit also includes assessing the accounting
+principles used and significant estimates made by management, as well as evaluating the overall
+financial statement presentation. We believe that our audits provide a reasonable basis for our
+opinion.
+In our opinion, the financial statements referred to above present fairly, in all material
+respects, the consolidated financial position of Callon Petroleum Company as of December 31, 2004
+and 2003, and the results of its operations and its cash flows for each of the three years in the
+period ended December 31, 2004, in conformity with accounting principles generally accepted in the
+United States.
+As discussed in Note 1 to the financial statements, effective January 1, 2003, the Company
+adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement
+Obligations”.
+We also have audited, in accordance with the standards of the Public Company Accounting
+Oversight Board (United States), the effectiveness of Callon Petroleum Company’s internal control
+over financial reporting as of December 31, 2004, based on criteria established in Internal
+Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
+Commission and our report dated March 8, 2005, expressed an unqualified opinion thereon.
+/s/Ernst & Young LLP 
+New Orleans, Louisiana 
+March 8, 2005
+44
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED BALANCE SHEETS 
+(In thousands, except share data) 
+December 31, 
+2004 
+2003 
+ASSETS 
+Current assets: 
+Cash and cash equivalents 
+$ 
+3,266 
+$ 
+8,700 
+Restricted cash 
+— 
+63,345 
+Accounts receivable 
+14,928 
+10,117 
+Deferred tax asset-current 
+5,676 
+— 
+Restricted investments-current 
+2,055 
+— 
+Fair market value
+of derivatives 
+1,570 
+— 
+Other current assets 
+581 
+3,606 
+Total current assets 
+28,076 
+85,768 
+Oil and gas properties, full-cost accounting method: 
+Evaluated properties 
+862,101 
+802,912 
+Less accumulated depreciation, depletion and amortization 
+(494,453 
+) 
+(447,000 
+) 
+367,648 
+355,912 
+Unevaluated properties excluded from amortization 
+39,042 
+34,251 
+Total oil and gas properties 
+406,690 
+390,163 
+Other property and equipment, net 
+1,541 
+1,547 
+Deferred tax asset 
+2,986 
+— 
+Long-term gas balancing receivable 
+725 
+1,101 
+Restricted investments 
+5,687 
+7,420 
+Investment in Medusa Spar LLC 
+9,787 
+8,471 
+Other assets, net 
+2,031 
+1,562 
+Total assets 
+$ 
+457,523 
+$ 
+496,032 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued liabilities 
+$ 
+15,728 
+$ 
+15,855 
+Fair market
+value of derivatives 
+2,993 
+165 
+Undistributed oil and gas revenues 
+1,162 
+897 
+Accrued net profits interest payable 
+1,927 
+1,886 
+Suspended
+Medusa oil royalties 
+5,430 
+— 
+Asset retirement obligations-current 
+13,300 
+8,571 
+Current maturities of long-term debt 
+576 
+93,223 
+Total current liabilities 
+41,116 
+120,597 
+Long-term debt 
+192,351 
+214,885 
+Asset retirement obligations 
+24,982 
+25,120 
+Other long-term liabilities 
+762 
+2,169 
+Total liabilities 
+259,211 
+362,771 
+Stockholders’ equity: 
+Preferred Stock, $.01 par value; 2,500,000 shares authorized;
+596,671 shares of Convertible Exchangeable Preferred Stock,
+Series A issued and outstanding at December 31, 2004
+with a liquidation preference of $14,916,775 
+6 
+6 
+Common Stock, $.01 par value; 30,000,000 shares
+authorized; 17,616,596 shares and 13,935,311 shares
+outstanding at December 31, 2004 and 2003, respectively 
+176 
+139 
+Unearned compensation-restricted stock 
+(5,352 
+) 
+(372 
+) 
+Capital in excess of par value 
+220,664 
+169,036 
+Other comprehensive loss 
+(1,883 
+) 
+(20 
+) 
+Retained earnings (deficit) 
+(15,299 
+) 
+(35,528 
+) 
+Total stockholders’ equity 
+198,312 
+133,261 
+Total liabilities and stockholders’ equity 
+$ 
+457,523 
+$ 
+496,032 
+The accompanying notes are an integral part of these financial statements.
+45
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Statements of Operations 
+For the Years Ended December 31, 2004, 2003 and 2002 
+(In thousands, except per share amounts) 
+2004 
+2003 
+2002 
+Operating revenues: 
+Oil and gas sales 
+$ 
+119,802 
+$ 
+73,697 
+$ 
+61,171 
+Operating expenses: 
+Lease operating expenses 
+22,308 
+11,301 
+11,030 
+Depreciation, depletion and amortization 
+47,453 
+28,253 
+27,096 
+General and administrative 
+8,758 
+4,713 
+4,705 
+Accretion expense 
+3,400 
+2,884 
+— 
+Derivative expense 
+1,371 
+535 
+708 
+Total operating expenses 
+83,290 
+47,686 
+43,539 
+Income from operations 
+36,512 
+26,011 
+17,632 
+Other (income) expenses: 
+Interest expense 
+20,137 
+30,614 
+26,140 
+Other (income) 
+(357 
+) 
+(444 
+) 
+(1,004 
+) 
+Loss on early extinguishment of debt 
+3,004 
+5,573 
+— 
+Gain on sale of pipeline 
+— 
+— 
+(2,454 
+) 
+Gain on sale of Enron derivatives 
+— 
+— 
+(2,479 
+) 
+Total other (income) expenses 
+22,784 
+35,743 
+20,203 
+Income (loss) before income taxes 
+13,728 
+(9,732 
+) 
+(2,571 
+) 
+Income tax expense (benefit) 
+(6,697 
+) 
+8,432 
+(900 
+) 
+Income (loss) before Medusa Spar LLC and cumulative
+effect of change in accounting principle 
+20,425 
+(18,164 
+) 
+(1,671 
+) 
+Income (loss) on Medusa Spar LLC, net of tax 
+1,076 
+(8 
+) 
+— 
+Income (loss) before cumulative effect of change in
+accounting principle 
+21,501 
+(18,172 
+) 
+(1,671 
+) 
+Cumulative effect of change in accounting principle, net of tax 
+— 
+181 
+— 
+Net income (loss) 
+21,501 
+(17,991 
+) 
+(1,671 
+) 
+Preferred stock dividends 
+1,272 
+1,277 
+1,277 
+Net income (loss) available to common shares 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+$ 
+(2,948 
+) 
+Net income (loss) per common share: 
+Basic
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+1.28 
+$ 
+(1.42 
+) 
+$ 
+(0.22 
+) 
+Cumulative effect of change in accounting principle, net of
+tax 
+— 
+0.01 
+— 
+Net income (loss) available to common 
+$ 
+1.28 
+$ 
+(1.41 
+) 
+$ 
+(0.22 
+) 
+Diluted
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+1.22 
+$ 
+(1.42 
+) 
+$ 
+(0.22 
+) 
+Cumulative effect of change in accounting principle, net of
+tax 
+— 
+0.01 
+— 
+Net income (loss) available to common 
+$ 
+1.22 
+$ 
+(1.41 
+) 
+$ 
+(0.22 
+) 
+Shares used in computing net income (loss): 
+Basic 
+15,796 
+13,662 
+13,387 
+Diluted 
+17,678 
+13,662 
+13,387 
+The accompanying notes are an integral part of these financial statements.
+46
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY 
+(In thousands) 
+Unearned 
+Accumulated 
+Total 
+Restricted 
+Capital in 
+Other 
+Retained 
+Stock- 
+Preferred 
+Common 
+Stock 
+Excess of 
+Comprehensive 
+Earnings 
+holders’ 
+Stock 
+Stock 
+Compensation 
+Par Value 
+Income (Loss) 
+(Deficit) 
+Equity 
+Balances, December 31, 2001 
+$ 
+6 
+$ 
+134 
+$ 
+— 
+$ 
+154,425 
+$ 
+5,971 
+$ 
+(13,312 
+) 
+$ 
+147,224 
+Comprehensive income (loss): 
+Net loss 
+— 
+— 
+— 
+— 
+— 
+(1,671 
+) 
+Other comprehensive loss 
+— 
+— 
+— 
+— 
+(6,440 
+) 
+— 
+Total comprehensive loss 
+(8,111 
+) 
+Preferred stock dividends 
+— 
+— 
+— 
+— 
+— 
+(1,277 
+) 
+(1,277 
+) 
+Shares issued pursuant to employee
+benefit and option plan 
+— 
+1 
+— 
+770 
+— 
+— 
+771 
+Employee stock purchase plan 
+— 
+— 
+— 
+79 
+— 
+— 
+79 
+Tax benefits related to stock
+compensation plans 
+— 
+— 
+— 
+(29 
+) 
+— 
+— 
+(29 
+) 
+Restricted stock 
+— 
+3 
+(826 
+) 
+1,849 
+— 
+— 
+1,026 
+Warrants 
+— 
+1 
+— 
+1,276 
+— 
+— 
+1,277 
+Balances, December 31, 2002 
+6 
+139 
+(826 
+) 
+158,370 
+(469 
+) 
+(16,260 
+) 
+140,960 
+Comprehensive income (loss): 
+Net loss 
+— 
+— 
+— 
+— 
+— 
+(17,991 
+) 
+Other comprehensive income 
+— 
+— 
+— 
+— 
+449 
+— 
+Total comprehensive loss 
+(17,542 
+) 
+Preferred stock dividends 
+— 
+— 
+— 
+— 
+— 
+(1,277 
+) 
+(1,277 
+) 
+Shares issued pursuant to employee
+benefit and option plan 
+— 
+1 
+— 
+427 
+— 
+— 
+428 
+Employee stock purchase plan 
+— 
+— 
+— 
+127 
+— 
+— 
+127 
+Restricted stock 
+— 
+(1 
+) 
+454 
+(516 
+) 
+— 
+— 
+(63 
+) 
+Warrants 
+— 
+— 
+— 
+10,628 
+— 
+— 
+10,628 
+Balances, December 31, 2003 
+6 
+139 
+(372 
+) 
+169,036 
+(20 
+) 
+(35,528 
+) 
+133,261 
+Comprehensive income (loss): 
+Net income 
+— 
+— 
+— 
+— 
+— 
+21,501 
+Other comprehensive (loss) 
+— 
+— 
+— 
+— 
+(1,863 
+) 
+— 
+Total comprehensive income 
+19,638 
+Preferred stock dividend 
+— 
+— 
+— 
+— 
+— 
+(1,272 
+) 
+(1,272 
+) 
+Sale of common stock 
+— 
+35 
+— 
+44,012 
+— 
+— 
+44,047 
+Shares issued pursuant to employee
+benefit and option plan 
+— 
+1 
+— 
+720 
+— 
+— 
+721 
+Employee stock purchase plan 
+— 
+1 
+— 
+208 
+— 
+— 
+209 
+Tax benefits related to stock
+compensation plans 
+— 
+— 
+— 
+1,214 
+— 
+— 
+1,214 
+Restricted stock 
+— 
+— 
+(4,980 
+) 
+5,474 
+— 
+— 
+494 
+Balances, December 31, 2004 
+$ 
+6 
+$ 
+176 
+$ 
+(5,352 
+) 
+$ 
+220,664 
+$ 
+(1,883 
+) 
+$ 
+(15,299 
+) 
+$ 
+198,312 
+The accompanying notes are an integral part of these financial statements.
+47
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+For the Years Ended December 31, 2004, 2003 and 2002 
+(In thousands) 
+2004 
+2003 
+2002 
+Cash flows from operating activities: 
+Net income (loss) 
+$ 
+21,501 
+$ 
+(17,991 
+) 
+$ 
+(1,671 
+) 
+Adjustments to reconcile net income (loss) to
+cash provided by operating activities: 
+Depreciation, depletion and amortization 
+48,164 
+29,264 
+27,774 
+Accretion expense 
+3,400 
+2,884 
+— 
+Amortization of deferred financing costs 
+1,929 
+6,568 
+5,521 
+Non-cash loss on extinguishment of debt 
+2,910 
+4,423 
+Amortization of deferred production payment revenue 
+— 
+— 
+(2,406 
+) 
+Income from investment in Medusa Spar, LLC 
+(1,076 
+) 
+— 
+— 
+Cumulative effect of change in accounting principle 
+— 
+(181 
+) 
+— 
+Non-cash derivative income 
+— 
+— 
+(9,186 
+) 
+Non-cash
+derivative expense 
+(135 
+) 
+487 
+708 
+Deferred income tax expense (benefit) 
+(6,697 
+) 
+8,432 
+(900 
+) 
+Gain on sale of pipeline 
+— 
+— 
+(2,454 
+) 
+Non-cash charge related to compensation plans 
+1,225 
+858 
+1,267 
+Changes in current assets and liabilities: 
+Accounts receivable, trade 
+(4,495 
+) 
+(1,438 
+) 
+(4,967 
+) 
+Other current assets 
+971 
+(2,667 
+) 
+(104 
+) 
+Current liabilities 
+2,903 
+5,185 
+3,198 
+Investment in derivative contracts 
+— 
+— 
+(1,687 
+) 
+Change in gas balancing receivable 
+376 
+(340 
+) 
+(288 
+) 
+Change in gas balancing payable 
+400 
+(491 
+) 
+(390 
+) 
+Change in other long-term liabilities 
+(20 
+) 
+(15 
+) 
+67 
+Change in other assets, net 
+(448 
+) 
+(349 
+) 
+(2,315 
+) 
+Cash provided (used) by operating activities 
+70,908 
+34,629 
+12,167 
+Cash flows from investing activities: 
+Capital expenditures 
+(64,649 
+) 
+(50,705 
+) 
+(66,023 
+) 
+Distribution from Medusa Spar, LLC 
+339 
+24,908 
+— 
+Proceeds from sale of pipeline and other facilities 
+— 
+1,500 
+6,784 
+Proceeds from sale of mineral interests 
+— 
+982 
+4,492 
+Cash provided (used) by investing activities 
+(64,310 
+) 
+(23,315 
+) 
+(54,747 
+) 
+Cash flows from financing activities: 
+Change in accounts payable and accrued liability to be refinanced 
+— 
+(3,861 
+) 
+(5,697 
+) 
+Increase in debt 
+90,000 
+198,000 
+109,900 
+Payments on debt 
+(205,915 
+) 
+(133,000 
+) 
+(58,085 
+) 
+Restricted cash 
+63,345 
+(63,345 
+) 
+— 
+Debt issuance cost 
+(984 
+) 
+(3,745 
+) 
+(2,291 
+) 
+Issuance of common stock 
+44,047 
+— 
+— 
+Equity issued related to employee stock plans 
+199 
+127 
+79 
+Capital leases 
+(1,452 
+) 
+(1,320 
+) 
+(1,129 
+) 
+Cash dividends on preferred stock 
+(1,272 
+) 
+(1,277 
+) 
+(1,277 
+) 
+Cash provided (used) by financing activities 
+(12,032 
+) 
+(8,421 
+) 
+41,500 
+Net increase (decrease) in cash and cash equivalents 
+(5,434 
+) 
+2,893 
+(1,080 
+) 
+Cash and short-term investments: 
+Balance, beginning of period 
+8,700 
+5,807 
+6,887 
+Balance, end of period 
+$ 
+3,266 
+$ 
+8,700 
+$ 
+5,807 
+The accompanying notes are an integral part of these financial statements.
+48
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+1. ORGANIZATION 
+General 
+Callon Petroleum Company (“the Company” or “Callon”) was organized under the laws of the state of
+Delaware in March 1994 to serve as the surviving entity in the consolidation and combination of
+several related entities (referred to herein collectively as the “Constituent Entities”). The
+combination of the businesses and properties of the Constituent Entities with the Company was
+completed on September 16, 1994 (“Consolidation”).
+As a result of the Consolidation, all of the businesses and properties of the Constituent Entities
+are owned (directly or indirectly) by the Company. Certain registration rights were granted to the
+stockholders of certain of the Constituent Entities. See Note 7.
+The Company and its predecessors have been engaged in the acquisition, development and exploration
+of crude oil and natural gas since 1950. The Company’s properties are geographically concentrated
+in Louisiana, Alabama and offshore Gulf of Mexico.
+2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 
+Principles of Consolidation and Reporting 
+The Consolidated Financial Statements include the accounts of the Company, and its subsidiary,
+Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries, namely Callon Offshore
+Production, Inc. and Mississippi Marketing, Inc. All intercompany accounts and transactions have
+been eliminated. Certain prior year amounts have been reclassified to conform to presentation in
+the current year.
+Use of Estimates 
+The preparation of financial statements in conformity with generally accepted accounting principles
+requires management to make estimates and assumptions that affect the reported amounts of assets
+and liabilities and disclosure of contingent assets and liabilities at the date of the financial
+statements and the reported amounts of revenues and expenses during the reporting period. Actual
+results could differ from those estimates.
+Accounting Pronouncements 
+On December 16, 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised
+2004), (“SFAS 123R”) Share-Based Payment, which is a revision of Statement of Financial Accounting
+Standards No. 123, (“SFAS 123”) Accounting for Stock-Based Compensation . SFAS 123R supersedes APB
+Opinion No. 25, Accounting for Stock Issued to Employees , and amends Statement of Financial
+Accounting Standards No. 95, Statement of Cash Flows . Generally, the approach in SFAS 123R is
+similar to the approach described in SFAS 123. However, SFAS 123R requires all share-based
+payments to
+49
+Table of Contents 
+employees, including grants of employee stock options, to be recognized in the income
+statement based on their fair values. Pro forma disclosure is no longer an alternative.
+SFAS 123R must be adopted no later than July 1, 2005. Early adoption will be permitted in periods
+in which financial statements have not yet been issued. SFAS 123R permits public companies to
+adopt its requirements using one of two methods below:
+• 
+A “modified prospective” method in which compensation cost is recognized beginning with
+the effective date (a) based on the requirements of SFAS 123R for all share-based payments
+granted after the effective date and (b) based on the requirements of SFAS 123 for all
+awards granted to employees prior to the effective date of SFAS 123R that remain unvested
+on the effective date; or 
+• 
+A “modified retrospective” method which includes the requirements of the modified
+prospective method described above, but also permits entities to restate based on the
+amounts previously recognized under SFAS 123 for purposes of pro forma disclosures either
+(a) all prior periods presented or (b) prior interim periods of the year of adoption. 
+The Company expects to adopt SFAS 123R on July 1, 2005 using the modified prospective method.
+As permitted by SFAS 123, the Company currently accounts for share-based payments to employees
+using Opinion 25’s intrinsic value method and, as such, generally recognizes no compensation cost
+for employee stock options. Accordingly, the adoption of SFAS 123R’s fair value method will have a
+significant impact on our result of operations, although it will have no impact on our overall
+financial position. The impact of adoption of SFAS 123R cannot be predicted at this time because
+it will depend on levels of share-based payments granted in the future. However, had we adopted
+SFAS 123R in prior periods, the impact of that standard would have approximated the impact of SFAS
+123 as described in the disclosure of pro forma net income and earnings per share below under
+Stock-Based Compensation.
+In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest
+Entities, an Interpretation of Accounting Research Bulletin (ARB) 51” (“FIN 46”). FIN 46 addresses
+consolidation by business enterprises of variable interest entities (“VIEs”). The primary
+objective of FIN 46 is to provide guidance on the identification of, and financial reporting for,
+entities over which control is achieved through means other than voting rights; such entities are
+known as VIEs. The Company adopted FIN 46, as revised, as of December 31, 2003, which had no
+impact on the Company’s results of operations or financial position.
+In September 2004, the Securities and Exchange Commission issued Staff Accounting Bulletin (“SAB”)
+No. 106 which expressed the Staff’s views regarding the application of Statement of Financial
+Accounting Standards (“SFAS”) No. 143 “Accounting for Asset Retirement Obligations” by oil and gas
+producing companies following the full-cost accounting method. SAB No. 106 specifies that
+subsequent to the adoption of SFAS No. 143 an oil and gas company following the full-cost method of
+accounting should include assets recorded in connection with the recognition of an asset retirement
+obligation pursuant to SFAS No. 143 as part of the costs subject to the full-cost ceiling
+limitation. The future cash outflows associated with settling the recorded asset retirement
+obligations should be excluded from the computation of the present value of estimated future net
+revenues used in applying the ceiling test. The Company will be required to adopt the provisions
+of SAB No. 106 prospectively in the first quarter of 2005 which will have no impact on the
+Company’s results of operation or financial position.
+Property and Equipment 
+The Company follows the full-cost method of accounting for oil and gas properties whereby all costs
+incurred in connection with the acquisition, exploration and development of oil and gas reserves,
+including
+50
+Table of Contents 
+certain overhead costs, are capitalized. Such amounts include the cost of drilling and
+equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest
+capitalized on unevaluated leases and other costs related to exploration and development
+activities. General and administrative costs capitalized include salaries and related fringe
+benefits paid to employees directly engaged in the acquisition, exploration and/or development of
+oil and gas properties as well as other directly identifiable general and administrative costs
+associated with such activities. Such capitalized costs ($7.2 million in 2004, $8.4 million in
+2003 and $9.6 million in 2002) do not include any costs related to production or general corporate
+overhead. Costs associated with unevaluated properties, including capitalized interest on such
+costs, are excluded from amortization. Unevaluated property costs are transferred to evaluated
+property costs at such time as wells are completed on the properties, the properties are sold or
+management determines that these costs have been impaired.
+Costs of properties, including future development and future site restoration, dismantlement and
+abandonment costs, which have proved reserves and properties which have been determined to be
+worthless, are depleted using the unit-of-production method based on proved reserves. If the total
+capitalized costs of oil and gas properties, net of accumulated amortization and deferred taxes
+relating to oil and gas properties, exceed the sum of (1) the estimated future net revenues from
+proved reserves at current prices and discounted at 10% and (2) the lower of cost or market of
+unevaluated properties (the full-cost ceiling amount), net of tax effects, then such excess is
+charged to expense during the period in which the excess occurs. See Note 9.
+Upon the acquisition or discovery of oil and gas properties, management estimates the future net
+costs to be incurred to dismantle, abandon and restore the property using available geological,
+engineering and regulatory data. Such cost estimates are periodically updated for changes in
+conditions and requirements. Such estimated amounts are considered as part of the full-cost pool
+subject to amortization upon acquisition or discovery. Until January 1, 2003, such costs were
+capitalized as oil and gas properties as the actual restoration, dismantlement and abandonment
+activities took place. As discussed below under Asset Retirement Obligations, beginning January 1,
+2003, the Company changed the method for which we account for such costs upon adoption of SFAS 143
+and these costs are now included in the full cost pool. For purposes of the full-cost ceiling
+test, the Company nets the Asset Retirement Obligation liability against the net capitalized costs
+of oil and gas properties and includes the future cash outflows associated with asset retirement
+obligations in the valuation of the full-cost ceiling amount.
+Depreciation of other property and equipment is provided using the straight-line method over
+estimated lives of three to 20 years. Depreciation of pipeline and other facilities is provided
+using the straight-line method over estimated lives of 15 to 27 years. Depreciation expense of
+$346,000, $578,000 and $696,000 relating to other property and equipment was included in general
+and administrative expenses in the Company’s statements of operations for the years ended December
+31, 2004, 2003 and 2002, respectively. The accumulated depreciation on other property and
+equipment was $10.4 million and $10.2 million as of December 31, 2004 and 2003, respectively.
+Investment in Medusa Spar LLC 
+In December 2003, the Company announced the formation of a limited liability company, Medusa Spar
+LLC, which now owns a 75% undivided ownership interest in the deepwater spar production facilities
+on Callon’s Medusa Field in the Gulf of Mexico. The Company contributed a 15% undivided ownership
+interest in the production facility to Medusa Spar LLC in return for approximately $25 million in
+cash and a 10% ownership interest in the LLC. The LLC will earn a tariff based upon production
+volume throughput from the Medusa area. Callon is obligated to process our share of production from
+the Medusa
+51
+Table of Contents 
+Field and any future discoveries in the area through the spar production facilities.
+This arrangement allows Callon to defer the cost of the spar production facility over the life of
+the Medusa Field. The Company’s cash proceeds were used to reduce the balance outstanding under
+its senior secured credit facility. The LLC used the cash proceeds from $83.7 million of
+non-recourse financing and a cash contribution by one of the LLC owners to acquire its 75% interest
+in the spar. On December 31, 2004, $64.1 million of the financing was outstanding. The balance of
+Medusa Spar LLC is owned by Oceaneering International, Inc. (NYSE:OII) and Murphy Oil Corporation
+(NYSE:MUR). The Company is accounting for our 10% ownership interest in the LLC under the equity
+method.
+Asset Retirement Obligations 
+In June 2001, the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for
+Asset Retirement Obligations (“SFAS 143”) effective for fiscal years beginning after June 15, 2002.
+SFAS 143 essentially requires entities to record the fair value of a liability for obligations
+associated with the retirement of tangible long-lived assets and the associated asset retirement
+costs. Callon adopted SFAS 143 on January 1, 2003 resulting in a cumulative effect of accounting
+change of $181,000, net of tax. See Note 8.
+Natural Gas Imbalances 
+The Company follows the entitlement method of accounting for its proportionate share of gas
+production on a well-by-well basis, recording a receivable to the extent that a well is in an
+“undertake” position and conversely recording a liability to the extent that a well is in an
+“overtake” position. Gas balancing receivables were
+$725,000 and $1.1 million as of December 31, 2004 and 2003,
+respectively. Gas balancing payables were $594,000 and $193,000 as of
+December 31, 2004 and 2003, respectively.
+Derivatives 
+The Company uses derivative financial instruments for price protection purposes on a limited amount
+of its future production and does not use them for trading purposes. Such derivatives are
+accounted for under SFAS 133. See Note 6
+Income Tax 
+The Company follows the asset and liability method of accounting for deferred income taxes
+prescribed by Statement of Financial Accounting Standards No. 109 (“SFAS 109”) “Accounting for
+Income Taxes”. The statement provides for the recognition of a deferred tax asset for deductible
+temporary timing differences, capital and operating loss carryforwards, statutory depletion
+carryforward and tax credit carryforwards, net of a “valuation allowance”. The valuation allowance
+is provided for that portion of the asset, for which it is deemed more likely than not, that it
+will not be realized. See Note 3.
+Accounts Receivable 
+Accounts receivable consists primarily of accrued oil and gas production receivables. The balance
+in the reserve for doubtful accounts included in accounts receivable was $103,000 at December 31,
+2004 and 2003. Net charge offs recorded against the reserve for doubtful accounts were $40,000 in
+2003. There were no provisions to expense in the three-year period ended December 31, 2004.
+52
+Table of Contents 
+Accounts Payable and Accrued Liabilities to be Refinanced 
+Amounts included in the Consolidated Balance Sheet represent capital expenditures in accounts
+payable and accrued liabilities that were refinanced with the availability under the Company’s
+senior secured credit facility subsequent to a specific Balance Sheet date. As of December 31,
+2004, there were no capital expenditures to be refinanced in the following month. Amounts in 2003
+were classified as short term because of the maturity of the credit facility on June 30, 2004.
+Sale of Production Payment Interest 
+In June 1999, the Company acquired a working interest in the Mobile Block 864 Area where the
+Company already owned an interest. Concurrent with this acquisition, the seller received a
+volumetric production payment, valued at approximately $14.8 million, from production attributable
+to a portion of the Company’s interest in the area over a 39-month period. The Company recorded
+deferred
+revenue associated with the sale of this production payment interest because a substantial
+obligation for future performance existed. Under the terms of the sale, the Company was obligated
+to deliver the production volumes free and clear of royalties, lease operating expenses, production
+taxes and all capital costs. The production payment was amortized, beginning in June 1999, to oil
+and gas sales on the units-of-production method as associated hydrocarbons were delivered, and
+expired in July 2002.
+Stock-Based Compensation 
+The Company’s pro forma net income (loss) and net income (loss) per share of common stock for the
+12-month periods ended December 31, 2004, 2003 and 2002 had compensation costs been recorded using
+the fair value method in accordance with SFAS 123, as amended by SFAS 148, are presented below
+pursuant to the disclosure requirements of SFAS 148 (in thousands except per share data):
+2004 
+2003 
+2002 
+(In thousands, except per share data) 
+Net income (loss) available to common shares,
+as reported 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+$ 
+(2,948 
+) 
+Stock-based compensation expense included
+in net income as reported, net of tax 
+348 
+17 
+270 
+Deduct: Total stock-based
+compensation expense under fair
+value based method, net of tax 
+(549 
+) 
+(247 
+) 
+(907 
+) 
+Pro forma net income (loss) available to
+common shares 
+$ 
+20,028 
+$ 
+(19,498 
+) 
+$ 
+(3,585 
+) 
+Basic
+earnings (loss) per share: As Reported 
+1.28 
+(1.41 
+) 
+(.22 
+) 
+Pro Forma 
+1.27 
+(1.43 
+) 
+(.27 
+) 
+Diluted earnings (loss) per share: As Reported 
+1.22 
+(1.41 
+) 
+(.22 
+) 
+Pro Forma 
+1.20 
+(1.43 
+) 
+(.27 
+) 
+See Note 12 for descriptions and additional disclosures related to the plans.
+53
+Table of Contents 
+Major Customers 
+The Company’s production is sold generally on month-to-month contracts at prevailing prices.
+The following table identifies customers to whom it sold a significant percentage of its total oil
+and gas production during each of the 12-month periods ended:
+December 31, 
+2004 
+2003 
+2002 
+Petrocom Energy Group, Ltd. 
+— 
+4 
+% 
+4 
+% 
+Dynegy 
+— 
+5 
+% 
+7 
+% 
+Prior Energy Corporation 
+— 
+20 
+% 
+— 
+Reliant Energy Services 
+6 
+% 
+28 
+% 
+70 
+% 
+Louis Dreyfus Energy Services 
+23 
+% 
+27 
+% 
+— 
+Shell Trading Company 
+30 
+% 
+— 
+— 
+Plains Marketing, L.P. 
+13 
+% 
+— 
+— 
+Conoco Phillips Company 
+8 
+% 
+— 
+— 
+Chevron Texaco Natural Gas 
+6 
+% 
+— 
+— 
+Because alternative purchasers of oil and gas are readily available, the Company believes that the
+loss of any of these purchasers would not result in a material adverse effect on its ability to
+market future oil and gas production.
+Statements of Cash Flows 
+For purposes of the Consolidated Financial Statements, the Company considers all highly liquid
+investments purchased with an original maturity of three months or less to be cash equivalents.
+The Company paid no federal income taxes for the three years in the period ended December 31,
+2004. During the years ended December 31, 2004, 2003 and 2002, the Company made cash payments for
+interest of $23,197,000, $27,913,000 and $25,507,000, respectively.
+Per Share Amounts 
+Basic income or loss per common share was computed by dividing net income or loss by the
+weighted average number of shares of common stock outstanding during the year. Diluted income or
+loss per common share was determined on a weighted average basis using common shares issued and
+outstanding adjusted for the effect of stock options considered common stock equivalents computed
+using the treasury stock method and the effect of the convertible preferred stock (if dilutive).
+The conversion of the preferred stock was not included in the annual calculation for 2003 and 2002
+due to its antidilutive effect on diluted income or loss per common share. In addition, below are
+the shares relating to stock options, warrants and restricted stock that were not included in
+diluted shares for the twelve-month periods ended December 31, 2003 and 2002 due to the fact that
+the Company had a loss for these periods. The Company had net income for the period ended December
+31, 2004 and all such shares were included as described below.
+54
+Table of Contents 
+Twelve Months Ended December 31, 
+(in thousands) 
+2003 
+2002 
+Stock options 
+63 
+13 
+Warrants 
+424 
+372 
+Restricted Stock 
+248 
+122 
+A reconciliation of the basic and diluted per share computation is as follows (in thousands, except
+per share amounts):
+2004 
+2003 
+2002 
+(a) Net income (loss) available to common shares 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+$ 
+(2,948 
+) 
+Preferred dividends assuming conversion of
+preferred stock (if dilutive) 
+1,272 
+— 
+— 
+(b) Income (loss) available to common shares assuming conversion of preferred stock (if dilutive) 
+$ 
+21,501 
+$ 
+(19,268 
+) 
+$ 
+(2,948 
+) 
+(c) Weighted average shares outstanding 
+15,796 
+13,662 
+13,387 
+Dilutive impact of stock options 
+233 
+— 
+— 
+Dilutive impact of restricted stock 
+75 
+— 
+— 
+Dilutive impact of warrants 
+894 
+— 
+— 
+Convertible preferred stock (if dilutive) 
+680 
+— 
+— 
+(d) Total diluted shares 
+17,678 
+13,662 
+13,387 
+Stock options and warrants excluded due to the
+exercise price being greater than the stock price 
+89 
+2,297 
+2,250 
+Basic income (loss) per share (a ¸ c) 
+$ 
+1.28 
+$ 
+(1.41 
+) 
+$ 
+(.22 
+) 
+Diluted income (loss) per share (b ¸ d) 
+$ 
+1.22 
+$ 
+(1.41 
+) 
+$ 
+(.22 
+) 
+Fair Value of Financial Instruments 
+Fair value of cash, cash equivalents, accounts receivable, accounts payable, the capital lease and
+the senior secured credit facility approximates book value at December 31, 2004 and 2003. Fair
+value of long-term debt (specifically, the 9.75% Senior Notes) had an estimated fair value of 106%
+of face value at December 31, 2004. Fair value of long-term debt (specifically, the 10.125%, the
+10.25%, and the 11% Senior Subordinated Notes and the 12% loans) had an estimated fair value of
+100% of face value at December 31, 2003.
+55
+Table of Contents 
+3. INCOME TAXES 
+The Company has recorded a net deferred tax asset at December 31, 2004 and 2003 and a valuation
+allowance at December 31, 2003 as follows:
+December 31, 
+2004 
+2003 
+(In thousands) 
+Federal net operating loss carryforwards 
+$ 
+56,271 
+$ 
+61,805 
+Statutory depletion carryforward 
+4,124 
+4,255 
+Alternative minimum tax credit carryforward 
+326 
+— 
+Temporary differences: 
+Oil and gas properties 
+(66,200 
+) 
+(66,725 
+) 
+Pipeline and other facilities 
+— 
+— 
+Non-oil and gas property 
+(77 
+) 
+(16 
+) 
+Other 
+1,988 
+2,031 
+SFAS 143-Asset Retirement Obligations 
+11,544 
+10,563 
+Permanent differences: 
+Employee benefits 
+787 
+(428 
+) 
+Other 
+(101 
+) 
+17 
+Total tax asset 
+8,662 
+11,502 
+Valuation allowance 
+— 
+(11,502 
+) 
+Net tax asset 
+$ 
+8,662 
+$ 
+— 
+SFAS 109 provides for the weighing of positive and negative evidence in determining whether it is
+more likely than not that a deferred tax asset is recoverable. The Company incurred losses in 2002
+and 2003 and had losses on an aggregate basis for the three-year period ended December 31, 2003.
+Because of these cumulative losses the Company established a full valuation allowance of $11.5
+million as of December 31, 2003.
+As a result of production from the Company’s first two deepwater projects starting in November
+2003, as well as refinancing its highest cost debt in 2004, the Company achieved profitable
+operations and has income on an aggregate basis for the three-year period ended December 31, 2004.
+Callon also expects 2005 production levels to exceed 2004 levels and expects to utilize most if not
+all of the deferred tax asset in 2005. As a result, the Company reversed the valuation allowance
+which had a balance of $7.0 million as of December 31, 2004.
+56
+Table of Contents 
+Below is a reconciliation of the reported amount of income tax expense attributable to continuing
+operations for the year to the amount of income tax expense that would result from applying
+domestic federal statutory tax rates to pretax income from continuing operations.
+Year Ended December 31, 
+2004 
+2003 
+2002 
+Income tax expense (benefit) computed at the statutory
+federal income tax rate 
+35 
+% 
+(35 
+%) 
+(35 
+%) 
+Change in valuation allowance 
+(84 
+%) 
+118 
+% 
+— 
+Write off of NOL’s 
+— 
+4 
+% 
+— 
+Effective income tax rate 
+(49 
+%) 
+87 
+% 
+(35 
+%) 
+If not utilized, the
+Company’s federal net operating loss carryforwards will expire in 2013
+through 2018.
+The Company has significant state net operating loss carryforwards that are not included in the
+deferred tax asset above, as the Company does not anticipate generating taxable state income in the
+states in which these loss carryforwards apply. The Company has very limited state taxable income
+as primarily all of its revenue is generated in federal waters not subject to state income taxes.
+4. OTHER COMPREHENSIVE INCOME 
+A recap of the Company’s 2004, 2003 and 2002 other comprehensive income (net of tax
+of $1.0 million, $242,000, and $3.5 million, respectively) is shown below
+(in thousands):
+Years Ended December 31, 
+2004 
+2003 
+2002 
+Other comprehensive income (loss): 
+Change in fair value of derivatives 
+$ 
+(1,863 
+) 
+$ 
+449 
+$ 
+(469 
+) 
+Amortization of Enron derivatives 
+— 
+— 
+(5,971 
+) 
+Total other comprehensive income (loss) 
+$ 
+(1,863 
+) 
+$ 
+449 
+$ 
+(6,440 
+) 
+57
+Table of Contents 
+5. LONG-TERM DEBT 
+Long-term debt consisted of the following at:
+December 31, 
+2004 
+2003 
+(In thousands) 
+Senior Secured Credit Facility 
+$ 
+5,000 
+$ 
+30,000 
+Senior Subordinated Notes (due 2004) – these
+notes were retired with restricted cash on
+01/08/2004: 
+10.125% notes net of discount 
+— 
+21,772 
+* 
+10.250% notes 
+— 
+40,000 
+* 
+12% Senior Loans (due 2005) net of discount 
+— 
+9,490 
+11% Senior Subordinated Notes (due 2005) 
+— 
+33,000 
+9.75% Senior Notes (due 2010) net of discount 
+186,216 
+170,684 
+Capital Lease 
+1,711 
+3,162 
+Total Long-term Debt 
+192,927 
+308,108 
+Less current portion 
+576 
+93,223 
+* 
+Long-term portion 
+$ 
+192,351 
+$ 
+214,885 
+* 
+$62.9 million of 2004 senior subordinated notes are in this current portion and were
+retired on January 8, 2004. 
+Senior Secured Credit Facility . On June 15, 2004, the Company closed on a three-year senior secured
+credit facility underwritten by Union Bank of California, N.A. (“Union Bank”) to replace the
+Company’s credit facility with Wachovia Bank, National Association (“Wachovia Bank”) which was
+expiring June 30, 2004. The credit facility includes an initial borrowing base of $60 million,
+which may be adjusted semi-annually and can be increased to a maximum of $175 million. Borrowings
+under the credit facility are secured by mortgages covering the Company’s five largest fields. The
+credit facility bears interest at 0.25% above a defined base rate depending on utilization of the
+borrowing base or, at the option of the Company, LIBOR plus 1.5% to 2.25% based on utilization of
+the borrowing base. Under the senior secured credit facility, a commitment fee of 0.25% or 0.375%
+per annum, depending on the amount of the unused portion of the borrowing base, is payable
+quarterly.
+The range of interest rates on the senior secured credit facilities for both Union Bank and
+Wachovia Bank combined were 3.09% to 5.50% for the 12 months ended December 31, 2004. The weighted
+average interest rate for the senior secured credit facilities debt outstanding at December 31,
+2004 and 2003 was 4.16% and 15%, respectively.
+As of December 31, 2004 there was $5.0 million outstanding under the facility and Callon had an
+aggregate of $2.3 million in outstanding letters of credit issued under the credit facility. These
+letters of credit secure obligations under the outstanding hedging contracts described in Note 6 to
+the Consolidated Financial Statements. The outstanding letters of credit reduce the amount
+available for borrowings under the credit facility. As a result, $52.7 million was available for
+future borrowings under the credit facility as of December 31, 2004.
+58
+Table of Contents 
+Restructured Debt . In December 2003 and in the first half of 2004, the Company completed several
+transactions which restructured all debt that was maturing through 2005. The transactions were
+• 
+borrowing $185 million pursuant to a senior unsecured credit facility for a term of
+seven years at an interest rate of 9.75% in December 2003; 
+• 
+the formation of Medusa Spar LLC in which the Company contributed its 15% ownership in
+the deepwater spar production facilities in return for a 10% interest in Medusa Spar LLC
+and approximately $25 million in cash; 
+• 
+borrowing an additional $15 million for a term of seven years at an interest rate of
+9.75% pursuant to a senior unsecured credit agreement in the first quarter of 2004; 
+• 
+closing a three-year senior secured credit facility with an initial borrowing base of
+$60 million in June 2004 which can be increased by the lender to $175 million; and 
+• 
+closing the public offering of 3,450,000 shares of common stock priced at $13.25 per
+share raising net proceeds of approximately $44 million, after expenses, in June 2004. 
+Below is a list of the debt which was extinguished and restructured with the funds raised from the
+transactions above.
+• 
+the Company’s $22.9 million, 10.125% senior subordinated notes due in 2004 
+• 
+the Company’s $40 million, 10.25% senior subordinated notes due in 2004 
+• 
+the Company’s $95 million, 12% senior unsecured credit facility due in 2005 
+• 
+the Company’s $33 million, 11% senior subordinated notes due in 2005 
+All of the above debt was extinguished before maturity which resulted in a loss on early
+extinguishment of debt for the twelve-month periods ended December 31, 2004 and 2003 of $3.0
+million and $5.6 million, respectively. In addition to restructuring the Company’s debt, Callon
+reduced the balance outstanding on its senior secured credit facility.
+9.75% Senior Notes (due 2010). In December 2003 the Company borrowed $185 million pursuant to
+a senior unsecured credit facility. The loans under the credit facility have a stated interest
+rate of 9.75% and a seven-year maturity. The net proceeds of $181.3 million were used to redeem
+$22.9 million of 10.125% senior subordinated notes due July 31, 2004, $40 million of 10.25% senior
+subordinated notes due September 15, 2004 and $85 million
+of our 12% loan due March 31, 2005 issued pursuant to a senior unsecured credit agreement dated
+July 29, 2001 plus a 1% pre-payment premium of $850,000, and to reduce the balance outstanding
+under the Company’s senior secured credit facility. In conjunction with the new senior unsecured
+notes, the Company issued detachable warrants to purchase 2.775 million shares of it’s common stock
+at an exercise price of $10 per share and an expiration date in
+December 2010. The warrants were valued at $10.6 million and were treated
+as a discount on the debt. This senior unsecured debt matures December 8, 2010 and has an
+effective interest rate of 11.4%. The Company recorded the issuance of these new securities at a
+fair value of $171 million. Deferred costs of $14 million associated with the notes will be
+amortized over the life of the notes.
+During March 2004, Callon borrowed an additional $15 million under its 9.75% senior unsecured
+credit facility bringing the total outstanding under the facility to $200 million. The net proceeds
+of approximately $14 million were primarily used to retire the remaining $10 million of 12% senior
+loans due March 31, 2005 plus a 1% call premium of $100,000. The Company recorded the issuance of
+these additional new securities at a fair value of $14 million. Deferred costs of $1 million
+associated with the notes will be amortized over the life of the notes.
+59
+Table of Contents 
+In March 2004, the $200 million in aggregate principal amount of loans outstanding under the
+9.75% senior unsecured credit facility were exchanged for 9.75% Senior Notes due 2010, Series A,
+“Series A notes”, issued pursuant to a senior indenture between Callon and American Stock Transfer
+& Trust Company dated March 15, 2004. On August 12, 2004, the Company completed an offer to
+exchange its 9.75% Senior Notes due 2010, Series B, that have been registered under the Securities
+Act of 1933, for all outstanding Series A notes.
+Capital Lease . In December 2001, the Company entered into a 10-year gas processing agreement
+associated with a production facility on Callon’s Mobile Block 952 Field with Hanover Compression
+Limited Partnership, which is being accounted for as a capital lease. Total minimum obligations
+are $8.4 million with interest representing approximately $2.8 million and the present value
+minimum obligations representing $5.6 million.
+Restrictive Covenants . The senior secured credit facility and the senior notes contain various
+covenants including restrictions on additional indebtedness and payment of cash dividends as well
+as maintenance of certain financial ratios. The Company was in compliance with these covenants at
+December 31, 2004.
+Future minimum lease payments and debt maturities (in thousands) are as follows: 
+Capital Lease 
+Year 
+Payments 
+Debt 
+2005 
+$ 
+822 
+$ 
+— 
+2006 
+439 
+— 
+2007 
+348 
+5,000 
+2008 
+228 
+— 
+2009 
+229 
+— 
+Thereafter 
+465 
+200,000 
+60
+Table of Contents 
+6. DERIVATIVES 
+The Company periodically uses derivative financial instruments to manage oil and gas price risk.
+Settlements on commodity price contracts are generally based upon the difference between the
+contract price or prices specified in the derivative instrument and a NYMEX price or other cash or
+futures index price.
+The Company’s derivative contracts that are accounted for as cash flow hedges under SFAS 133 are
+recorded at fair market value and the changes in fair value are recorded through other
+comprehensive income (loss), net of tax, in stockholders’ equity. The cash settlements on these
+contracts are recorded as an increase or decrease in oil and gas sales. Cash settlements on the
+derivative contracts for the twelve-month periods ended December 31, 2004 and 2003 resulted in a
+reduction of oil and gas sales in the amount of $13.8 million and $2.9 million, respectively, and
+an increase in oil and gas sales of $9.2 million for the twelve-month period ended December 31,
+2002.
+The changes in fair value of the Company’s derivative contracts that are not designated as
+effective cash flow hedges are recorded through the statement of operations as derivative expense.
+In addition, the change in fair value relating to the ineffective portion of cash flow hedges is
+recorded as derivative expense. The following table summarizes derivative expense for the periods
+presented (in thousands):
+December 31, 
+2004 
+2003 
+2002 
+Ineffective portion of hedges qualifying for hedge
+accounting included in derivative expense 
+$ 
+(1,209 
+) 
+$ 
+— 
+$ 
+— 
+Non-designated derivative contracts included in
+derivative expense 
+(162 
+) 
+(535 
+) 
+(708 
+) 
+$ 
+(1,371 
+) 
+$ 
+(535 
+) 
+$ 
+(708 
+) 
+61
+Table of Contents 
+The fair value of all the oil and a portion of the gas derivative contracts at December 31, 2004
+was a current liability of $2,993,000. The fair value of the remaining portion of the gas
+derivative contracts was a current asset of $1,570,000.
+Listed in the table below are the outstanding derivative contracts as of December 31,
+2004:
+Swaps
+Volumes per 
+Quantity 
+Average 
+Product 
+Month 
+Type 
+Price 
+Period 
+Oil 
+30,000 
+Bbls 
+$ 
+31.29 
+01/05 
+Oil 
+15,000 
+Bbls 
+$ 
+30.00 
+01/05-03/05 
+Puts
+Volumes per 
+Quantity 
+Average 
+Product 
+Month 
+Type 
+Price 
+Period 
+Oil 
+50,000 
+Bbls 
+$ 
+35.00 
+02/05-06/05 
+Oil 
+7,000 
+Bbls 
+$ 
+35.00 
+01/05-12/05 
+Natural Gas 
+270,000 
+MMBtu 
+$ 
+5.00 
+04/05-10/05 
+Natural Gas 
+120,000 
+MMBtu 
+$ 
+5.00 
+01/05-10/05 
+Natural Gas 
+100,000 
+MMBtu 
+$ 
+5.00 
+04/05-12/05 
+Natural Gas 
+300,000 
+MMBtu 
+$ 
+6.50 
+01/05-03/05 
+Collars
+Average 
+Average 
+Volumes per 
+Quantity 
+Floor 
+Ceiling 
+Product 
+Month 
+Type 
+Price 
+Price 
+Period 
+Oil 
+45,000 
+Bbls 
+$ 
+29.33 
+$ 
+32.17 
+01/05 
+Oil 
+15,000 
+Bbls 
+$ 
+32.50 
+$ 
+40.00 
+01/05-12/05 
+Oil 
+15,208 
+Bbls 
+$ 
+40.00 
+$ 
+50.00 
+01/05-12/05 
+Oil 
+15,000 
+Bbls 
+$ 
+32.50 
+$ 
+40.00 
+02/05-12/05 
+Oil 
+15,000 
+Bbls 
+$ 
+35.00 
+$ 
+43.50 
+03/05-12/05 
+Natural Gas 
+300,000 
+MMBtu 
+$ 
+5.00 
+$ 
+6.91 
+01/05-03/05 
+Natural Gas 
+190,000 
+MMBtu 
+$ 
+5.00 
+$ 
+12.80 
+01/05-03/05 
+Natural Gas 
+100,000 
+MMBtu 
+$ 
+5.00 
+$ 
+7.75 
+04/05-10/05 
+Natural Gas 
+200,000 
+MMBtu 
+$ 
+5.75 
+$ 
+7.75 
+04/05-10/05 
+7. COMMITMENTS AND CONTINGENCIES 
+As described in Note 11, abandonment trusts (the “Trusts”) have been established for future
+abandonment obligations of those oil and gas properties of the Company burdened by a net profits
+interest. The management of the Company believes the Trusts will be sufficient to offset those
+future abandonment liabilities; however, the Company is responsible for any abandonment expenses in
+excess of the Trusts’ balances. As of December 31, 2004, total estimated site restoration,
+dismantlement and abandonment costs were approximately $7.8 million, net of expected salvage value.
+Substantially all such costs are expected to be funded through the Trusts’ funds, all of which
+will be accessible to the Company when abandonment work begins. In addition, as a working interest
+owner and/or operator of oil and gas properties, the Company is responsible for the cost of
+abandonment of such properties. See Notes 2 and 8.
+62
+Table of Contents 
+From time to time, the Company, as part of the Consolidation and other capital transactions,
+entered into registration rights agreements whereby certain parties to the transactions are
+entitled to require the Company to register common stock of the Company owned by them with the
+Securities and Exchange Commission for sale to the public in firm commitment public offerings and
+generally to include shares owned by them, at no cost, in registration statements filed by the
+Company. Costs of the offering will not include broker’s discounts and commissions, which will be
+paid by the respective sellers of the common stock.
+The Company is involved in various claims and lawsuits incidental to its business. In the opinion
+of management, the ultimate liability thereunder, if any, will not have a material adverse effect
+on the financial position or results of operations of the Company.
+The Company’s Medusa deepwater property is eligible for royalty suspensions pursuant to the Deep
+Water Royalty Relief Act. However, the federal offshore leases covering this property contains
+“price threshold” provisions for oil and gas prices. Under these “price threshold” provisions, if
+the average monthly New York Mercantile Exchange (NYMEX) sales price for oil or gas during a fiscal
+year exceeds the price threshold for oil or gas, respectively, then royalties on the associated
+production must be paid to the Minerals Management Service (MMS) at the rate stipulated in the
+lease. The price thresholds are adjusted annually by the implicit price deflator for the GDP. The
+determination of whether or not royalties are due as a result of the average NYMEX price exceeding
+the price threshold is made during the first quarter of the succeeding year. Any royalty payments
+due must be made shortly after this determination is made. If a royalty payment is due for all
+production during a year as a result of exceeding the price threshold, the lessee is required to
+make monthly royalty payments during the succeeding fiscal year for the succeeding year’s
+production. If at the end of any year the average NYMEX price is below the price threshold, the
+lessee can apply for a refund for any associated royalties paid during that year and the lessee
+will not be required to pay royalties monthly during the succeeding year for the succeeding year’s
+production.
+The thresholds and the average NYMEX prices are calculated by the MMS. The average NYMEX price for
+2004 was $41.38 per barrel of oil and $6.18 per MMBtu of natural gas. For the year ended December
+31, 2004 the thresholds were $34.23 per barrel of oil
+and $4.28 per MMBtu of natural gas, subject to finalization of the adjustment for the 2004 GDP
+implicit price deflator. The Company was required to make monthly royalty payments for 2004 gas
+production. The Company accrued payments for 2004 oil royalties and will be required to pay these
+royalties to the MMS in the first quarter of 2005 after finalization of the price threshold. The
+Company will be required to make monthly royalty payments for both oil and gas production for 2005.
+In the year succeeding the year in which any of the Company’s properties became subject to
+royalties as the result of the average NYMEX price exceeding the price threshold, the portion of
+reserves attributable to potential future royalties would not be included in a year-end reserve
+report. However, if the average NYMEX prices were below the price thresholds in subsequent years,
+our reserves would be increased to reflect reserves previously attributed to future royalties. As
+a result, reported oil and gas reserves could materially increase or decrease, depending on the
+relation of price thresholds versus the average NYMEX prices. The reduction in revenues resulting
+from an obligation to pay these royalties and subsequent reduction of proved reserves could have a
+material adverse effect on the Company’s results of operations and financial condition. The
+Company’s reserve report as of December 31, 2004 excluded oil and gas reserves for Medusa that are
+subject to MMS royalties as a result of the average 2004 NYMEX prices for oil and gas exceeding the
+price thresholds.
+63
+Table of Contents 
+The Company’s activities are subject to federal, state and local laws and regulations governing
+environmental quality and pollution control. Although no assurances can be made, the Company
+believes that, absent the occurrence of an extraordinary event, compliance with existing federal,
+state and local laws, rules and regulating the release of materials in the environment or otherwise
+relating to the protection of the environment will not have a material effect upon the capital
+expenditures, earnings or the competitive position of the Company with respect to its existing
+assets and operations. The Company cannot predict what effect additional regulation or
+legislation, enforcement polices thereunder, and claims for damages to property, employees, other
+persons and the environment resulting from the Company’s operations could have on its activities.
+8. ASSET RETIREMENT OBLIGATIONS 
+As discussed in Note 2, the Company adopted SFAS 143 on January 1, 2003. The impact of adopting
+the statement resulted in a gain of $181,000, net of tax, which was reported as a cumulative effect
+of change in accounting principle.
+Approximately $30.3 million was recorded as the present value of asset retirement obligations
+on January 1, 2003 with the adoption of SFAS 143 related to the Company’s oil and gas properties.
+Interest is accreted on this amount and reported as accretion expense in the Consolidated
+Statements of Operations.
+Assets, primarily short-term U.S. Government securities, of approximately $7.7 million at December
+31, 2004, of which $2.1 million is current, are recorded as restricted investments. These assets
+are held in abandonment trusts dedicated to pay future abandonment costs of oil and gas properties
+in which the Company has sold a net profits interest. If there is any excess of trust assets over
+abandonment costs, the excess will be distributed to the net profits interest owners.
+The following table summarizes the activity for the Company’s asset retirement obligation:
+Twelve Months Ended 
+December 31, 2004 
+December 31, 2003 
+Asset retirement obligation at beginning of period 
+$ 
+33,691 
+$ 
+— 
+Liability recognized upon adoption 
+— 
+30,251 
+Accretion expense 
+3,400 
+2,884 
+Net profits interest accretion 
+459 
+371 
+Liabilities incurred 
+3,065 
+3,649 
+Liabilities settled 
+(2,076 
+) 
+(2,847 
+) 
+Revisions to estimate 
+(257 
+) 
+(617 
+) 
+Asset retirement obligation at end of period 
+38,282 
+33,691 
+Less: current retirement obligation 
+(13,300 
+) 
+(8,571 
+) 
+Long-term retirement obligation 
+$ 
+24,982 
+$ 
+25,120 
+Pro forma net income and earnings per share are not presented for the 12 months ended December 31,
+2002 because the pro forma application of SFAS 143 to the prior periods would not result in pro
+forma net income and earnings per share materially different from the actual amounts reported for
+the periods in the accompanying Consolidated Statements of Operations.
+64
+Table of Contents 
+9. OIL AND GAS PROPERTIES 
+The following table discloses certain financial data relating to the Company’s oil and gas
+activities, all of which are located in the United States.
+Years Ended December 31, 
+2004 
+2003 
+2002 
+(In thousands) 
+Capitalized costs incurred: 
+Evaluated Properties-
+Beginning of period balance 
+$ 
+802,912 
+$ 
+762,918 
+$ 
+704,937 
+Property acquisition costs 
+1,355 
+1,154 
+1,471 
+Exploration costs 
+26,749 
+21,390 
+17,851 
+Development costs 
+32,004 
+33,972 
+43,151 
+SFAS 143-Asset Retirement Obligation 
+(918 
+) 
+18,002 
+— 
+Medusa Spar transaction 
+— 
+(33,542 
+) 
+— 
+Sale of mineral interests 
+(1 
+) 
+(982 
+) 
+(4,492 
+) 
+End of period balance 
+$ 
+862,101 
+$ 
+802,912 
+$ 
+762,918 
+Unevaluated Properties (excluded from
+amortization) -
+Beginning of period balance 
+$ 
+34,251 
+$ 
+40,997 
+$ 
+37,560 
+Additions 
+16,367 
+5,228 
+5,802 
+Capitalized interest 
+4,577 
+4,862 
+5,289 
+Transfers to evaluated 
+(16,153 
+) 
+(16,836 
+) 
+(7,654 
+) 
+End of period balance 
+$ 
+39,042 
+$ 
+34,251 
+$ 
+40,997 
+Accumulated depreciation, depletion
+and amortization-
+Beginning of period balance 
+$ 
+447,000 
+$ 
+426,254 
+$ 
+399,339 
+Provision charged to expense 
+47,453 
+28,195 
+26,915 
+Cumulative effect of change in accounting
+Principle 
+— 
+(7,449 
+) 
+— 
+End of period balance 
+$ 
+494,453 
+$ 
+447,000 
+$ 
+426,254 
+Unevaluated property costs, primarily lease acquisition costs incurred at federal and state
+lease sales, unevaluated drilling costs, capitalized interest and general and administrative costs
+being excluded from the amortizable evaluated property base, consisted of $10.2 million incurred in
+2004, $7.5 million incurred in 2003 and $21.3 million incurred in 2002 and prior. These costs are
+directly related to the acquisition and evaluation of unproved properties and major development
+projects. The excluded costs and related reserves are included in the amortization base as the
+properties are evaluated and proved reserves are established or impairment is determined. The
+Company expects that the majority of these costs will be evaluated over the next three to five-year
+period.
+Depletion per unit-of-production (thousand cubic feet of gas equivalent) amounted to $2.18, $2.03
+and $1.73 for the years ended December 31, 2004, 2003, and 2002, respectively.
+Under the full-cost accounting rules of the SEC, the Company reviews the carrying value of its
+proved oil and gas properties each quarter. Under these rules, capitalized costs of proved oil and
+gas properties net of accumulated depreciation, depletion and amortization (DD&A) and deferred
+income taxes, may not exceed the present value of estimated future net cash flows from proved oil
+and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved
+properties included in the costs being amortized, net of related tax effects. These rules
+generally require pricing future oil and gas production at the unescalated market price for oil and
+gas at the end of each fiscal quarter and require a write-down if the “ceiling” is exceeded, unless
+prices recover sufficiently before the date of the auditor’s report. Given the volatility of oil
+and gas prices, it is reasonably possible that the Company’s estimate of discounted future net cash
+flows from proved oil and gas reserves could change in the near term. If oil and gas prices
+decline significantly, even if only for a short period of time, it is possible that writedowns of
+oil and gas properties could occur in the future.
+65
+Table of Contents 
+of related tax effects. These rules generally require pricing future oil and gas production
+at the unescalated market price for oil and gas at the end of each fiscal quarter and require a
+write-down if the “ceiling” is exceeded, unless prices recover sufficiently before the date of the
+auditor’s report. Given the volatility of oil and gas prices, it is reasonably possible that the
+Company’s estimate of discounted future net cash flows from proved oil and gas reserves could
+change in the near term. If oil and gas prices decline significantly, even if only for a short
+period of time, it is possible that writedowns of oil and gas properties could occur in the future.
+10. CONSOLIDATING CONDENSED FINANCIAL INFORMATION 
+Certain of the Company’s subsidiaries have fully and unconditionally guaranteed the payment of all
+obligations under the Company’s $200 million 9.75% Senior Notes due 2010 and the $175 million
+senior secured credit facility. The following tables present the consolidating condensed financial
+information of Callon Petroleum Company, as the parent company, and guarantor subsidiaries of
+Callon Petroleum Company balance sheets as of December 31, 2004 and December 31, 2003, and
+statements of income and cash flows for the twelve-month periods ended December 31, 2004, December
+31, 2003 and December 31, 2002.
+Callon Petroleum Company 
+Consolidating Condensed Guarantor Subsidiaries and Parent Company 
+Financial Information As of December 31, 2004 and December 31, 2003 
+And For The Twelve-Month Periods Ended 
+December 31, 2004, December 31, 2003 and December 31, 2002 
+Unaudited 
+(In thousands) 
+Callon Petroleum 
+Consolidating 
+Company 
+and 
+Callon Petroleum 
+(Parent 
+Guarantor 
+Eliminating 
+Company 
+Obligor) 
+Subsidiaries 
+Entries 
+Consolidated 
+As of December 31, 2004 
+Balance Sheet 
+Current assets 
+$ 
+728 
+$ 
+27,348 
+$ 
+— 
+$ 
+28,076 
+Intercompany receivables 
+297,480 
+— 
+(297,480 
+) 
+— 
+Investment in subsidiaries 
+90,253 
+1,903 
+(92,156 
+) 
+— 
+Oil and gas properties 
+1,463 
+405,227 
+— 
+406,690 
+Other assets 
+2,357 
+20,400 
+— 
+22,757 
+Total assets 
+$ 
+392,281 
+$ 
+454,878 
+$ 
+(389,636 
+) 
+$ 
+457,523 
+Current liabilities 
+$ 
+634 
+$ 
+40,482 
+— 
+41,116 
+Intercompany payables 
+— 
+297,480 
+(297,480 
+) 
+— 
+Long-term debt, less
+current maturities 
+191,216 
+1,135 
+— 
+192,351 
+Other accrued liabilities 
+236 
+25,508 
+— 
+25,744 
+Stockholders’ equity 
+200,195 
+90,273 
+(92,156 
+) 
+198,312 
+Total liabilities and
+stockholders’ equity 
+$ 
+392,281 
+$ 
+454,878 
+$ 
+(389,636 
+) 
+$ 
+457,523 
+66
+Table of Contents 
+Callon Petroleum 
+Consolidating 
+Company 
+and 
+Callon Petroleum 
+(Parent 
+Guarantor 
+Eliminating 
+Company 
+Obligor) 
+Subsidiaries 
+Entries 
+Consolidated 
+As of December 31, 2003 
+Balance Sheet 
+Current assets 
+$ 
+64,300 
+$ 
+21,468 
+$ 
+— 
+$ 
+85,768 
+Intercompany receivables 
+317,394 
+— 
+(317,394 
+) 
+— 
+Investment in subsidiaries 
+54,247 
+2,039 
+(56,286 
+) 
+— 
+Oil and gas properties 
+3,129 
+387,034 
+— 
+390,163 
+Other assets 
+1,557 
+18,544 
+— 
+20,101 
+Total assets 
+$ 
+440,627 
+$ 
+429,085 
+$ 
+(373,680 
+) 
+$ 
+496,032 
+Current liabilities 
+$ 
+93,846 
+$ 
+26,751 
+$ 
+— 
+$ 
+120,597 
+Intercompany payables 
+— 
+317,394 
+(317,394 
+) 
+— 
+Long-term debt, less current maturities 
+213,173 
+1,712 
+— 
+214,885 
+Other accrued liabilities 
+327 
+26,962 
+— 
+27,289 
+Stockholders’ equity 
+133,281 
+56,266 
+(56,286 
+) 
+133,261 
+Total liabilities and
+stockholders’ equity 
+$ 
+440,627 
+$ 
+429,085 
+$ 
+(373,680 
+) 
+$ 
+496,032 
+67
+Table of Contents 
+Callon Petroleum 
+Consolidating 
+Company 
+and 
+Callon Petroleum 
+(Parent 
+Guarantor 
+Eliminating 
+Company 
+Obligor) 
+Subsidiaries 
+Entries 
+Consolidated 
+For The Twelve Months Ended December 31, 2004 
+Statement of Income 
+Operating revenues: 
+Oil and gas sales 
+$ 
+4,614 
+$ 
+115,188 
+$ 
+— 
+$ 
+119,802 
+Total operating revenues 
+4,614 
+115,188 
+— 
+119,802 
+Operating expenses: 
+Lease operating expenses 
+472 
+21,836 
+— 
+22,308 
+Depreciation, depletion and
+amortization 
+1,772 
+45,681 
+— 
+47,453 
+General and administrative 
+1,652 
+7,106 
+— 
+8,758 
+Accretion expense 
+13 
+3,387 
+— 
+3,400 
+Derivative expense 
+— 
+1,371 
+— 
+1,371 
+Total operating expenses 
+3,909 
+79,381 
+— 
+83,290 
+Income from operations 
+705 
+35,807 
+— 
+36,512 
+Other (income) expenses: 
+Interest expense 
+403 
+19,734 
+— 
+20,137 
+Other income 
+(252 
+) 
+(105 
+) 
+— 
+(357 
+) 
+Loss on early extinguishment of
+debt 
+60 
+2,944 
+— 
+3,004 
+Equity in earnings of subsidiaries 
+(21,007 
+) 
+— 
+21,007 
+— 
+Total other (income) expenses 
+(20,796 
+) 
+22,573 
+21,007 
+22,784 
+Income (loss) before income taxes 
+21,501 
+13,234 
+(21,007 
+) 
+13,728 
+Income tax expense (benefit) 
+— 
+(6,697 
+) 
+— 
+(6,697 
+) 
+Income (loss) before Medusa Spar
+LLC 
+21,501 
+19,931 
+(21,007 
+) 
+20,425 
+Income from Medusa Spar LLC, net
+of tax 
+— 
+1,076 
+— 
+1,076 
+Net Income (loss) 
+21,501 
+21,007 
+(21,007 
+) 
+21,501 
+Preferred stock dividends 
+1,272 
+— 
+— 
+1,272 
+Net income 
+$ 
+20,229 
+$ 
+21,007 
+$ 
+(21,007 
+) 
+$ 
+20,229 
+68
+Table of Contents 
+Callon Petroleum 
+Consolidating 
+Company 
+and 
+Callon Petroleum 
+(Parent 
+Guarantor 
+Eliminating 
+Company 
+Obligor) 
+Subsidiaries 
+Entries 
+Consolidated 
+For The Twelve Months Ended December 31, 2003 
+Statement of Income 
+Operating revenues: 
+Oil and gas sales 
+$ 
+4,108 
+$ 
+69,589 
+$ 
+— 
+$ 
+73,697 
+Total operating revenues 
+4,108 
+69,589 
+— 
+73,697 
+Operating expenses: 
+Lease operating expenses 
+452 
+10,849 
+— 
+11,301 
+Depreciation, depletion and amortization 
+1,624 
+26,629 
+— 
+28,253 
+General and administrative 
+1,260 
+3,453 
+— 
+4,713 
+Accretion expense 
+20 
+2,864 
+— 
+2,884 
+Derivative expense 
+— 
+535 
+— 
+535 
+Total operating expenses 
+3,356 
+44,330 
+— 
+47,686 
+Income from operations 
+752 
+25,259 
+— 
+26,011 
+Other (income) expenses: 
+Interest expense 
+704 
+29,910 
+— 
+30,614 
+Other income 
+(199 
+) 
+(245 
+) 
+— 
+(444 
+) 
+Loss on early extinguishment of debt 
+128 
+5,445 
+— 
+5,573 
+Equity in earnings of subsidiaries 
+20,697 
+— 
+(20,697 
+) 
+— 
+Total other (income) expenses 
+21,330 
+35,110 
+(20,697 
+) 
+35,743 
+Income (loss) before income taxes 
+(20,578 
+) 
+(9,851 
+) 
+20,697 
+(9,732 
+) 
+Income tax expense (benefit) 
+(2,553 
+) 
+10,985 
+— 
+8,432 
+Income (loss) before Medusa Spar LLC
+and cumulative effect of change in
+accounting principle 
+(18,025 
+) 
+(20,836 
+) 
+20,697 
+(18,164 
+) 
+Loss from Medusa Spar LLC, net of tax 
+— 
+(8 
+) 
+— 
+(8 
+) 
+Income (loss) before cumulative effect
+of change in accounting principle 
+(18,025 
+) 
+(20,844 
+) 
+(20,697 
+) 
+(18,172 
+) 
+Cumulative effect of change in
+accounting principle, net of tax 
+34 
+147 
+— 
+181 
+Net Income (loss) 
+(17,991 
+) 
+(20,697 
+) 
+20,697 
+(17,991 
+) 
+Preferred stock dividends 
+1,277 
+— 
+— 
+1,277 
+Net income 
+$ 
+(19,268 
+) 
+$ 
+(20,697 
+) 
+$ 
+20,697 
+$ 
+(19,268 
+) 
+69
+Table of Contents 
+Callon Petroleum 
+Consolidating 
+Company 
+and 
+Callon Petroleum 
+(Parent 
+Guarantor 
+Eliminating 
+Company 
+Obligor) 
+Subsidiaries 
+Entries 
+Consolidated 
+For The Twelve Months Ended December 31, 2002 
+Statement of Income 
+Operating revenues: 
+Oil and gas sales 
+$ 
+3,064 
+$ 
+58,107 
+$ 
+— 
+$ 
+61,171 
+Total operating revenues 
+3,064 
+58,107 
+— 
+61,171 
+Operating expenses: 
+Lease operating expenses 
+1,273 
+9,757 
+— 
+11,030 
+Depreciation, depletion and amortization 
+1,579 
+25,517 
+— 
+27,096 
+General and administrative 
+1,163 
+3,542 
+— 
+4,705 
+Accretion expense 
+— 
+— 
+— 
+— 
+Derivative expense 
+— 
+708 
+— 
+708 
+Total operating expenses 
+4,015 
+39,524 
+— 
+43,539 
+Income from operations 
+(951 
+) 
+18,583 
+— 
+17,632 
+Other (income) expenses: 
+Interest expense 
+836 
+25,304 
+— 
+26,140 
+Other income 
+(1,623 
+) 
+(4,314 
+) 
+— 
+(5,937 
+) 
+Loss on early extinguishment of debt 
+— 
+— 
+— 
+— 
+Equity in earnings of subsidiaries 
+1,565 
+— 
+(1,565 
+) 
+— 
+Total other (income) expenses 
+778 
+20,990 
+(1,565 
+) 
+20,203 
+Income (loss) before income taxes 
+(1,729 
+) 
+(2,407 
+) 
+1,565 
+(2,571 
+) 
+Income tax expense (benefit) 
+(58 
+) 
+(842 
+) 
+— 
+(900 
+) 
+Income (loss) before cumulative effect
+of change in accounting principle 
+(1,671 
+) 
+(1,565 
+) 
+1,565 
+(1,671 
+) 
+Cumulative effect of change in
+accounting principle, net of tax 
+— 
+— 
+— 
+— 
+Net Income (loss) 
+(1,671 
+) 
+(1,565 
+) 
+1,565 
+(1,671 
+) 
+Preferred stock dividends 
+1,277 
+— 
+— 
+1,277 
+Net income 
+$ 
+(2,948 
+) 
+$ 
+(1,565 
+) 
+$ 
+1,565 
+$ 
+(2,948 
+) 
+70
+Table of Contents 
+Callon Petroleum 
+Consolidating 
+Company 
+and 
+Callon Petroleum 
+(Parent 
+Guarantor 
+Eliminating 
+Company 
+Obligor) 
+Subsidiaries 
+Entries 
+Consolidated 
+For The Twelve Months Ended December 31, 2004 
+Statement of Cash Flow 
+Net cash provided
+(used in) operating
+activities 
+$ 
+10,315 
+$ 
+60,593 
+$ 
+— 
+$ 
+70,908 
+Net cash provided by
+(used in) investing
+activities 
+(210 
+) 
+(64,100 
+) 
+— 
+(64,310 
+) 
+Net cash provided by
+(used in) financing
+activities 
+(10,580 
+) 
+(1,452 
+) 
+— 
+(12,032 
+) 
+Net increase
+(decrease) in cash
+and cash equivalents 
+(475 
+) 
+(4,959 
+) 
+— 
+(5,434 
+) 
+Cash and cash
+equivalents at
+beginning of the
+period 
+486 
+8,214 
+— 
+8,700 
+Cash and cash
+equivalents at end of
+the period 
+$ 
+11 
+$ 
+3,255 
+$ 
+— 
+$ 
+3,266 
+Callon Petroleum 
+Consolidating 
+Company 
+and 
+Callon Petroleum 
+(Parent 
+Guarantor 
+Eliminating 
+Company 
+Obligor) 
+Subsidiaries 
+Entries 
+Consolidated 
+For The Twelve Months Ended December 31, 2003 
+Statement of Cash Flow 
+Net cash provided
+(used in) operating
+activities 
+$ 
+3,547 
+$ 
+31,082 
+$ 
+— 
+$ 
+34,629 
+Net cash provided by
+(used in) investing
+activities 
+(12 
+) 
+(23,303 
+) 
+— 
+(23,315 
+) 
+Net cash provided by
+(used in) financing
+activities 
+(3,240 
+) 
+(5,181 
+) 
+— 
+(8,421 
+) 
+Net increase
+(decrease) in cash
+and cash equivalents 
+295 
+2,598 
+— 
+2,893 
+Cash and cash
+equivalents at
+beginning of the
+period 
+191 
+5,616 
+— 
+5,807 
+Cash and cash
+equivalents at end of
+the period 
+$ 
+486 
+$ 
+8,214 
+$ 
+— 
+$ 
+8,700 
+Callon Petroleum 
+Consolidating 
+Company 
+and 
+Callon Petroleum 
+(Parent 
+Guarantor 
+Eliminating 
+Company 
+Obligor) 
+Subsidiaries 
+Entries 
+Consolidated 
+For The Twelve Months Ended December 31, 2002 
+Statement of Cash Flow 
+Net cash provided
+(used in) operating
+activities 
+$ 
+(52,696 
+) 
+$ 
+64,863 
+$ 
+— 
+$ 
+12,167 
+Net cash provided by
+(used in) investing
+activities 
+4,044 
+(58,791 
+) 
+— 
+(54,747 
+) 
+Net cash provided by
+(used in) financing
+activities 
+48,326 
+(6,826 
+) 
+— 
+41,500 
+Net increase
+(decrease) in cash
+and cash equivalents 
+(326 
+) 
+(754 
+) 
+— 
+(1,080 
+) 
+Cash and cash
+equivalents at
+beginning of the
+period 
+517 
+6,370 
+— 
+6,887 
+Cash and cash
+equivalents at end of
+the period 
+$ 
+191 
+$ 
+5,616 
+$ 
+— 
+$ 
+5,807 
+71
+Table of Contents 
+11. NET PROFITS INTEREST 
+From 1989 through 1994, the Constituent Entities entered into separate agreements to purchase
+certain oil and gas properties with gross contract acquisition prices of $170,000,000 ($150,000,000
+net as of closing dates) and in simultaneous transactions, entered into agreements to sell
+overriding royalty interests (“ORRI”) in the acquired properties. These ORRI are in the form of
+net profits interests (“NPI”) equal to a significant percentage of the excess of gross proceeds
+over production costs, as defined, from the acquired oil and gas properties. A net deficit
+incurred in any month can be carried forward to subsequent months until such deficit is fully
+recovered. The Company has the right to abandon the purchased oil and gas properties if it deems
+the properties to be uneconomical.
+The Company has, pursuant to the purchase agreements, created abandonment trusts (see Note 7)
+whereby funds are provided out of gross production proceeds from the properties for the estimated
+amount of future abandonment obligations related to the working interests owned by the Company.
+The Trusts are administered by unrelated third party trustees for the benefit of the Company’s
+working interest in each property. The Trust agreements limit disbursement of funds to the
+satisfaction of abandonment obligations. Any funds remaining in the Trusts after all restoration,
+dismantlement and abandonment obligations have been met will be distributed to the owners of the
+properties in the same ratio as contributions to the Trusts. Estimated future revenues and costs
+associated with the NPI and the Trusts are also excluded from the oil and gas reserve disclosures
+at Note 14. As of December 31, 2004 and 2003, the Trusts’ assets (all cash and investments)
+totaled $7,742,000 and $7,420,000 respectively, all of which will be available to the Company to
+pay its portion, as working interest owner, of the restoration, dismantlement and abandonment costs
+discussed at Note 7. SFAS 143, discussed in Note 2 and 8, does not allow the Abandonment Trusts’
+assets to be used to offset the associated abandonment liability. The Company did not record any
+income or loss associated with the Trust asset or abandonment liability as a result of adoption of
+SFAS 143.
+At the time of acquisition of properties by the Company, the property owners estimated the future
+costs to be incurred for site restoration, dismantlement and abandonment, net of salvage value. A
+portion of the amounts necessary to pay such estimated costs was deposited in the Trusts upon
+acquisition of the properties, and the remainder is deposited from time to time out of the proceeds
+from production. The determination of the amount deposited upon the acquisition of the properties
+and the amount to be deposited as proceeds from production was based on numerous factors, including
+the estimated reserves of the properties.
+As operator, the Company receives all of the revenues and incurs all of the production costs for
+the purchased oil and gas properties but retains only that portion applicable to its net ownership
+share. As a result, the payables and receivables associated with operating the properties included
+in the Company’s Consolidated Balance Sheets include both the Company’s and all other outside
+owners’ shares. However, revenues and production costs associated with the acquired properties
+reflected in the accompanying Consolidated Statements of Operations represent only the Company’s
+share, after reduction for the NPI.
+72
+Table of Contents 
+12. EMPLOYEE BENEFIT PLANS 
+The Company has adopted a series of incentive compensation plans designed to align the interest of
+the executives and employees with those of its stockholders. The following is a brief description
+of each plan:
+The Savings and Protection Plan provides employees with the option to defer
+receipt of a portion of their compensation and the Company may, at its discretion,
+match a portion of the employee’s deferral with cash and Company Common Stock. The
+Company may also elect, at its discretion, to contribute a non-matching amount in
+cash and Company Common Stock to employees. The amounts held under the Savings and
+Protection Plan are invested in various funds maintained by a third party in
+accordance with the directions of each employee. An employee is fully vested,
+including Company discretionary contributions, immediately upon participation in the
+Savings and Protection Plan. The total amounts contributed by the Company,
+including the value of the common stock contributed, were $528,000, $562,000 and
+$611,000 in the years 2004, 2003 and 2002, respectively.
+The 1994 Stock Incentive Plan (the “1994 Plan”), approved by the shareholders
+in 1994, provides for 600,000 shares of Common Stock to be reserved for issuance
+pursuant to such plan. Under the 1994 Plan, the Company may grant both stock
+options qualifying under Section 422 of the Internal Revenue Code and options that
+are not qualified as incentive stock options, as well as performance shares. These
+options have an expiration date of 10 years from the date of grant.
+On August 23, 1996, the Board of Directors of the Company approved and adopted
+the Callon Petroleum Company 1996 Stock Incentive Plan (the “1996 Plan”). The 1996
+Plan was approved by the shareholders in 1997 and provides for the same types of
+awards as the 1994 Plan and is limited to a maximum of 1,200,000 shares (as amended
+from the original 900,000 shares) of common stock that may be subject to outstanding
+awards. Unvested options are subject to forfeiture upon certain termination of
+employment events and expire 10 years from the date of grant.
+The Company granted 533,000 stock options to employees on March 23, 2000 and
+120,000 stock options to directors on July 25, 2000 at $10.50 per share. The March
+23, 2000 grant was subject to shareholder approval of an amendment to the 1996 Stock
+Incentive Plan. The amendment, which was approved on May 9, 2000 at the Annual
+Meeting of Shareholders, increased the number of shares reserved for issuance under
+the 1996 plan to 2,200,000 shares. The excess of the market price over the exercise
+price on the approval date of the amendment was amortized over the three-year
+vesting period of the options. Compensation costs of $27,000 and $416,000 were
+recognized in 2003, and 2002, respectively, related to these options.
+In 2004, the Company awarded 430,000 performance shares from the 1994 and 1996
+Plans. These shares vest to the recipients over a five-year period (one-fifth in
+each year) beginning in July 2005. The deferred compensation portion of this grant
+will be amortized to expense over the vesting period. The non-cash amortization
+expense in 2004 was $532,000. In addition, 25,000 stock options were awarded to
+directors at $12.40 from the 1994 Plan.
+73
+Table of Contents 
+On February 14, 2002, the Board of Directors of the Company approved and adopted
+the 2002 Stock Incentive Plan (the “2002 Plan”). Pursuant to the 2002 Plan, 350,000
+shares of common stock shall be reserved for issuance upon the exercise of options or
+for grants of stock options, stock appreciation rights or units, bonus stock, or
+performance shares or units. This Plan qualified as a “broadly based” plan under the
+provisions of the New York Stock Exchange’s rules and regulations and therefore did
+not require shareholder approval. Because the 2002 Plan is a broadly based plan, the
+aggregate number of shares underlying awards granted to officers and directors cannot
+exceed 50% of the total number of shares underlying the awards granted to all
+employees during any three-year period.
+In 2002, the Company awarded 300,000 shares of restricted stock from the 1996 and the
+2002 Plan and 70,500 from treasury shares to be issued as vested. The issuance of
+the restricted stock using treasury shares did not require shareholder approval
+pursuant to the New York Stock Exchange’s rules and regulations, and therefore
+shareholder approval was not sought. These shares will generally vest to the
+recipients over a three-year period (one-third in each year) beginning in November
+2002. The deferred compensation portion of this grant will be amortized to expense
+over the vesting period. The non-cash amortization expense in 2004, 2003 and 2002 was
+$374,000, $454,000 and $496,000, respectively.
+In 1997, the Board of Directors authorized the implementation of the Callon Petroleum
+Company 1997 Employee Stock Purchase Plan (the “1997 Purchase Plan”), which was
+approved by the Company’s shareholders at the 1997 Annual Meeting. The Plan provides
+eligible employees of the Company with the opportunity to acquire a proprietary
+interest in the Company through participation in a payroll deduction-based employee
+stock purchase plan. An aggregate of 250,000 shares of common stock have been
+reserved for issuance over the 10-year term of the 1997 Purchase Plan. The purchase
+price per share at which common stock will be purchased on the participant’s behalf
+on each purchase date within an offering period is equal to 85 percent of the fair
+market value per share of common stock. As of December 31, 2004 there were no
+remaining shares available for purchase.
+A summary of the status of the Company’s stock option plans for the three most recent years and
+changes during the years then ended is presented in the table and narrative below:
+2004 
+2003 
+2002 
+Wtd Avg 
+Wtd Avg 
+Wtd Avg 
+Shares 
+Ex Price 
+Shares 
+Ex Price 
+Shares 
+Ex Price 
+Outstanding, beginning of year 
+2,450,867 
+$ 
+9.84 
+2,520,417 
+$ 
+9.90 
+2,332,667 
+$ 
+10.84 
+Granted (at market) 
+25,000 
+12.40 
+30,000 
+5.12 
+310,000 
+4.45 
+Exercised 
+(437,918 
+) 
+9.74 
+(500 
+) 
+4.10 
+— 
+— 
+Forfeited 
+(525,350 
+) 
+9.80 
+(99,050 
+) 
+9.74 
+(122,250 
+) 
+14.10 
+Expired 
+— 
+— 
+— 
+— 
+— 
+— 
+Outstanding, end of year 
+1,512,599 
+$ 
+9.93 
+2,450,867 
+$ 
+9.84 
+2,520,417 
+$ 
+9.90 
+Exercisable, end of year 
+1,446,486 
+$ 
+10.20 
+2,262,067 
+$ 
+10.31 
+2,224,334 
+$ 
+10.57 
+Weighted average fair value of
+options granted (at market) 
+$ 
+4.48 
+$ 
+2.97 
+$ 
+2.44 
+74
+Table of Contents 
+The following table sets forth additional information regarding options outstanding at
+December 31, 2004. Contractual life and exercise prices represent weighted averages for options
+outstanding and options exercisable.
+Options Outstanding 
+Options Exercisable 
+Range of 
+Number 
+Contractual 
+Exercise 
+Number 
+Exercise 
+exercise prices 
+Outstanding 
+Life (years) 
+Price 
+Exercisable 
+Price 
+$ 3.70 to 
+$ 
+6.41 
+237,999 
+7.5 
+$ 
+4.56 
+171,886 
+$ 
+4.72 
+$ 9.00 to 
+$ 
+12.40 
+1,209,600 
+3.9 
+$ 
+10.76 
+1,209,600 
+$ 
+10.76 
+$13.56 to 
+$ 
+15.31 
+65,000 
+3.2 
+$ 
+14.16 
+65,000 
+$ 
+14.16 
+The fair value of each option grant is estimated on the date of grant using the Black-Scholes
+option pricing model with the following weighted average assumptions used for options granted
+during the years presented are as follows:
+2004 
+2003 
+2002 
+Risk free interest rate 
+3.7 
+% 
+4.0 
+% 
+3.7 
+% 
+Expected life (years) 
+5.0 
+5.0 
+5.0 
+Expected volatility 
+45.1 
+% 
+65.3 
+% 
+61.0 
+% 
+Expected dividends 
+— 
+— 
+— 
+13. EQUITY TRANSACTIONS 
+On June 22, 2004, we closed the public offering of three million shares of common stock priced at
+$13.25 per share raising net proceeds of approximately $38.2 million, after expenses. In addition,
+we granted the underwriter, Johnson Rice & Company L.L.C., an over-allotment option to purchase an
+additional 450,000 shares. On June 30, 2004, the underwriter exercised the over-allotment option
+for an additional 450,000 shares priced at $13.25 per share, raising the net proceeds of the
+offering by approximately $5.7 million, after expenses. The proceeds from the transactions were
+used to redeem $33 million of the 11% Senior Subordinated Notes due December 15, 2005 and for
+general corporate purposes.
+In November 1995, the Company sold 1,315,500 shares of $2.125 Convertible Exchangeable Preferred
+Stock, Series A, and $0.01 par value per share (the Preferred Stock”) for net proceeds of $30.9
+million. Annual dividends are $2.125 per share and are cumulative. The net proceeds of the
+issuance of the Preferred Stock, after underwriters discount and expenses, were $30,899,000. Each
+share has a liquidation preference of $25.00, plus accrued and unpaid dividends. Dividends on the
+Preferred Stock are cumulative from the date of issuance and are payable quarterly, commencing
+January 15, 1996. The Preferred Stock is convertible at any time, at the option of the holders
+thereof, unless previously redeemed, into shares of Common Stock of the Company at an initial
+conversion price of $11 per share of Common Stock, subject to adjustments under certain conditions.
+The Preferred Stock is redeemable at any time on or after December 31, 1998, in whole or in part at
+the option of the Company at a redemption price of $26.488 per share beginning at December 31, 1998
+and at premiums declining to the $25.00 liquidation preference by the year 2005 and thereafter,
+plus accrued and unpaid dividends. The Preferred Stock is also exchangeable, in whole, but not in
+part, at the option of the Company on or after January 15, 1998 for the Company’s 8.5% Convertible
+Subordinated Debentures due 2010 (the “Debentures”) at a rate of $25.00 principal amount of
+Debentures for each share of Preferred
+75
+Table of Contents 
+Stock. The Debentures will be convertible into Common Stock of the Company on the same terms as the Preferred Stock and will pay interest semi-annually.
+In a December 1998 private transaction, a preferred stockholder elected to convert 59,689 shares of
+Preferred Stock into 136,867 shares of the Company’s Common Stock. In 1999 certain other preferred
+stockholders, through private transactions, agreed to convert 210,350 shares of Preferred Stock
+into 502,637 shares of the Company’s Common Stock under similar terms. Likewise in 2000, 444,600
+shares of Preferred Stock were converted into 1,036,098 shares of the Company’s Common Stock. Any
+non-cash premium negotiated in excess of the conversion rate was recorded as additional preferred
+stock dividends and excluded from the Consolidated Statements of Cash Flows.
+The Company adopted a stockholder rights plan on March 30, 2000, designed to assure that the
+Company’s stockholders receive fair and equal treatment in the event of any proposed takeover of
+the Company and to guard against partial tender offers, squeeze-outs, open market accumulations,
+and other abusive tactics to gain control without paying all stockholders a fair price. The rights
+plan was not adopted in response to any specific takeover proposal. Under the rights plan, the
+Company declared a dividend of one right (“Right”) on each share of the Company’s Common Stock.
+Each Right will entitle the holder to purchase one one-thousandth of a share of a Series B
+Preferred Stock, par value $0.01 per share, at an exercise price of $90 per one one-thousandth of a
+share.
+The Rights are not currently exercisable and will become exercisable only in the event a person or
+group acquires, or engages in a tender or exchange offer to acquire, beneficial ownership of 15
+percent or more (one existing stockholder was granted an exception for up to 21 percent) of the
+Company’s Common Stock. After the Rights become exercisable, each Right will also entitle its
+holder to purchase a number of common shares of the Company having a market value of twice the
+exercise price. The dividend distribution was made to stockholders of record at the close of
+business on April 10, 2000. The Rights will expire on March 30, 2010.
+14. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED) 
+The Company’s proved oil and gas reserves at December 31, 2004, 2003 and 2002 have been estimated
+by independent petroleum consultants in accordance with guidelines established by the Securities
+and Exchange Commission (“SEC”). Accordingly, the following reserve estimates are based upon
+existing economic and operating conditions. These estimates have been adjusted to exclude reserves
+attributable to the volumetric production payment described in Note 2.
+There are numerous uncertainties inherent in establishing quantities of proved reserves. The
+following reserve data represents estimates only and should not be construed as being exact. In
+addition, the standardized measure of discounted future net cash flows should not be construed as
+the current market value of the Company’s oil and gas properties or the cost that would be incurred
+to obtain equivalent reserves. See Note 7 regarding the Deep Water Royalty Relief Act and the loss
+of reserves.
+76
+Table of Contents 
+Estimated Reserves 
+Changes in the estimated net quantities of crude oil and natural gas reserves, all of which are
+located onshore and offshore in the continental United States, are as follows:
+Reserve Quantities 
+Years Ended December 31, 
+2004 
+2003 
+2002 
+Proved developed and undeveloped reserves: 
+Crude Oil (MBbls): 
+Beginning of period 
+23,709 
+24,043 
+30,209 
+Revisions to previous estimates 
+(2,370 
+)(b) 
+(1 
+) 
+(8,699 
+)(a) 
+Purchase of reserves in place 
+— 
+— 
+— 
+Sales of reserves in place 
+— 
+(65 
+) 
+— 
+Extensions and discoveries 
+145 
+— 
+2,759 
+(a) 
+Production 
+(1,736 
+) 
+(268 
+) 
+(226 
+) 
+End of period 
+19,748 
+23,709 
+24,043 
+Natural Gas (MMcf): 
+Beginning of period 
+74,691 
+91,539 
+120,299 
+Revisions to previous estimates 
+2,138 
+(6,407 
+)(b) 
+(19,284 
+)(a) 
+Purchase of reserves in place 
+— 
+— 
+— 
+Sales of reserves in place 
+— 
+(49 
+) 
+— 
+Extensions and discoveries 
+7,177 
+1,923 
+3,584 
+(a) 
+Production 
+(11,387 
+) 
+(12,315 
+) 
+(13,060 
+) 
+End of period 
+72,619 
+74,691 
+91,539 
+Proved developed reserves: 
+Crude Oil (MBbls): 
+Beginning of period 
+9,919 
+1,056 
+885 
+End of period 
+10,292 
+9,919 
+1,056 
+Natural Gas (MMcf): 
+Beginning of period 
+31,415 
+37,631 
+51,221 
+End of period 
+33,982 
+31,415 
+37,631 
+(a) 
+For the year ended December 31, 2002, revisions to previous estimates and extensions and
+discoveries were adjusted from the amounts reported in the Company’s Annual Report on Form
+10-K dated March 27, 2003 to reflect the subsequent changes in properties that were part of
+property acquisitions or exploratory drilling programs and should have been classified as
+extensions instead of revisions. 
+(b) 
+Includes Medusa royalty adjustment 
+77
+Table of Contents 
+Standardized Measure 
+The following tables present the Company’s standardized measure of discounted future net cash flows
+and changes therein relating to proved oil and gas reserves and were computed using reserve
+valuations based on regulations prescribed by the SEC. These regulations provide that the oil,
+condensate and gas price structure utilized to project future net cash flows reflects current
+prices (approximately $6.51 per Mcf for natural gas and $36.72 per Bbl for oil for the 2004
+disclosures, $5.99 per Mcf and $30.50 per Bbl for 2003 disclosures, and $4.80 per Mcf and $34.22
+per Bbl for 2002 disclosures) at each date presented and have not been escalated. Future
+production, development and net abandonment costs are based on current costs without escalation.
+The resulting net future cash flows have been discounted to their present values based on a 10%
+annual discount factor.
+Standardized Measure 
+Years Ended December 31, 
+2004 
+2003 
+2002 
+(In thousands) 
+Future cash inflows 
+$ 
+1,198,096 
+$ 
+1,170,118 
+$ 
+1,261,571 
+Future costs - 
+Production 
+(231,616 
+) 
+(219,421 
+) 
+(165,559 
+) 
+Development and net abandonment 
+(74,335 
+) 
+(111,850 
+) 
+(125,813 
+) 
+Future net inflows before income taxes 
+892,145 
+838,847 
+970,199 
+Future income taxes 
+(166,284 
+) 
+(89,567 
+) 
+(119,020 
+) 
+Future net cash flows 
+725,861 
+749,280 
+851,179 
+10% discount factor 
+(209,968 
+) 
+(230,254 
+) 
+(295,133 
+) 
+Standardized measure of discounted
+future net cash flows 
+$ 
+515,893 
+$ 
+519,026 
+$ 
+556,046 
+Changes in Standardized Measure 
+Years Ended December 31, 
+2004 
+2003 
+2002 
+(In thousands) 
+Standardized measure – beginning of period 
+$ 
+519,026 
+$ 
+556,046 
+$ 
+254,857 
+Sales and transfers, net of production costs 
+(97,494 
+) 
+(62,396 
+) 
+(38,375 
+) 
+Net change in sales and transfer prices,
+net of production costs 
+86,551 
+(41,011 
+) 
+401,837 
+Exchange and sale of in place reserves 
+— 
+(1,226 
+) 
+— 
+Purchases, extensions, discoveries, and
+improved
+recovery, net of future production and
+development costs incurred 
+77,576 
+25,632 
+8,456 
+Revisions of quantity estimates 
+(41,314 
+) 
+(18,018 
+) 
+(103,452 
+) 
+Accretion of discount 
+57,046 
+62,394 
+26,915 
+Net change in income taxes 
+(45,262 
+) 
+16,460 
+(53,608 
+) 
+Changes in production rates, timing and other 
+(40,236 
+) 
+(18,855 
+) 
+59,416 
+Standardized measure — end of period 
+$ 
+515,893 
+$ 
+519,026 
+$ 
+556,046 
+78
+Table of Contents 
+15. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) 
+First 
+Second 
+Third 
+Fourth 
+Quarter 
+Quarter 
+Quarter 
+Quarter 
+(In thousands, except per share data) 
+2004 
+Total revenues 
+$ 
+31,919 
+$ 
+37,606 
+$ 
+25,138 
+$ 
+25,139 
+Income from operations 
+10,231 
+14,543 
+5,367 
+6,371 
+Net income (loss) 
+2,102 
+9,730 
+546 
+9,123 
+(a) 
+Net income (loss) per common share-basic 
+$ 
+0.13 
+$ 
+0.66 
+$ 
+0.01 
+$ 
+0.50 
+(a) 
+Net income (loss) per common share-diluted 
+0.12 
+0.58 
+0.01 
+0.45 
+(a) 
+First 
+Second 
+Third 
+Fourth 
+Quarter 
+Quarter 
+Quarter 
+Quarter 
+(In thousands, except per share data) 
+2003 
+Total revenues 
+$ 
+21,268 
+$ 
+18,409 
+$ 
+15,082 
+$ 
+18,938 
+Income from operations 
+8,946 
+6,422 
+4,366 
+6,277 
+Income (loss) before cumulative effect of change
+in accounting principle 
+1,201 
+(647 
+) 
+(2,026 
+) 
+(16,700 
+)(b) 
+Net income (loss) 
+1,382 
+(647 
+) 
+(2,026 
+) 
+(16,700 
+)(b) 
+Net income (loss) per common share-basic: 
+Net income (loss) available to common before
+cumulative effect of change in accounting
+principle 
+$ 
+0.07 
+($ 
+0.07 
+) 
+($ 
+0.17 
+) 
+($ 
+1.24 
+)(b) 
+Cumulative effect of change in accounting
+principle,
+net of tax 
+0.01 
+0.00 
+0.00 
+0.00 
+Net income (loss) per share 
+$ 
+0.08 
+($ 
+0.07 
+) 
+($ 
+0.17 
+) 
+($ 
+1.24 
+)(b) 
+Net income (loss) per common share-diluted: 
+Net income (loss) available to common before
+cumulative effect of change in accounting
+principle 
+$ 
+0.07 
+($ 
+0.07 
+) 
+($ 
+0.17 
+) 
+($ 
+1.24 
+)(b) 
+Cumulative effect of change in accounting
+principle,
+net of tax 
+0.01 
+0.00 
+0.00 
+0.00 
+Net income (loss) per share 
+$ 
+0.08 
+($ 
+0.07 
+) 
+($ 
+0.17 
+) 
+($ 
+1.24 
+)(b) 
+(a) 
+The fourth quarter of 2004 includes a tax benefit of $6.7 million resulting from the
+elimination of the valuation allowance established in 2003. See Note 3. 
+(b) 
+The fourth quarter of 2003 includes the establishment of a deferred tax valuation
+allowance of $11.5. See Note 3. 
+79
+Table of Contents 
+ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+There have been no disagreements with the independent auditors on any matters of accounting
+principles or practices, financial statement disclosure, or auditing scope or procedures.
+ITEM 9.A CONTROLS AND PROCEDURES 
+The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the
+Securities Exchange Act of 1934, or the Exchange Act. This term refers to the controls and
+procedures of a company that are designed to ensure that information required to be disclosed by a
+company in the reports that it files or submits under the Exchange Act is recorded, processed,
+summarized and reported within the time periods specified by the Securities and Exchange
+Commission. Our management, including our Chief Executive Officer and Chief Financial Officer, has
+evaluated the effectiveness of our disclosure controls and procedures as of the end of the period
+covered by this annual report. Based upon that evaluation, our Chief Executive Officer and Chief
+Financial Officer have concluded that our disclosure controls and procedures were effective as of
+the end of the period covered by this annual report.
+Management’s Report On Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over
+financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the
+supervision and with the participation of our management, including our principal executive officer
+and principal financial officer, we conducted an evaluation of the effectiveness of our internal
+control over financial reporting as of December 31, 2004 based on the frame work in the Internal
+Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
+Commission. Based on our evaluation under the framework in Internal Control-Integrated Framework,
+our management concluded that our internal control over financial reporting was effective as of
+December 31, 2004.
+Ernst & Young LLP, our independent registered public accounting firm, has issued an attestation
+report on our management’s assessment of the effectiveness of our internal control over financial
+reporting which is included herein.
+Changes In Internal Control Over Financial Reporting 
+There were no changes to our internal control over financial reporting during our last fiscal
+quarter that has materially affected, or is reasonably likely to materially affect, our internal
+control over financial reporting.
+80
+Table of Contents 
+Report of Independent Registered Public Accounting Firm
+The Stockholders and Board of Directors 
+Callon Petroleum Company
+We have audited management’s assessment, included in the accompanying Management’s Report on
+Internal Control over Financial Reporting, that Callon Petroleum Company maintained effective
+internal control over financial reporting as of December 31, 2004, based on criteria established in
+Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the
+Treadway Commission (the COSO criteria). Callon Petroleum Company’s management is responsible for
+maintaining effective internal control over financial reporting and for its assessment of the
+effectiveness of internal control over financial reporting. Our responsibility is to express an
+opinion on management’s assessment and an opinion on the effectiveness of the company’s internal
+control over financial reporting based on our audit.
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
+Board (United States). Those standards require that we plan and perform the audit to obtain
+reasonable assurance about whether effective internal control over financial reporting was
+maintained in all material respects. Our audit included obtaining an understanding of internal
+control over financial reporting, evaluating management’s assessment, testing and evaluating the
+design and operating effectiveness of internal control, and performing such other procedures as we
+considered necessary in the circumstances. We believe that our audit provides a reasonable basis
+for our opinion.
+A company’s internal control over financial reporting is a process designed to provide reasonable
+assurance regarding the reliability of financial reporting and the preparation of financial
+statements for external purposes in accordance with generally accepted accounting principles. A
+company’s internal control over financial reporting includes those policies and procedures that (1)
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
+transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
+transactions are recorded as necessary to permit preparation of financial statements in accordance
+with generally accepted accounting principles, and that receipts and expenditures of the company
+are being made only in accordance with authorizations of management and directors of the company;
+and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
+acquisition, use, or disposition of the company’s assets that could have a material effect on the
+financial statements.
+Because of its inherent limitations, internal control over financial reporting may not prevent or
+detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
+subject to the risk that controls may become inadequate because of changes in conditions, or that
+the degree of compliance with the policies or procedures may deteriorate.
+81
+Table of Contents 
+In our opinion, management’s assessment that Callon Petroleum Company maintained effective internal
+control over financial reporting as of December 31, 2004, is fairly stated, in all material
+respects, based on the COSO criteria. Also, in our opinion, Callon Petroleum Company maintained, in all material
+respects, effective internal control over financial reporting as of December 31, 2004, based on the
+COSO criteria.
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight
+Board (United States), the consolidated balance sheets of Callon Petroleum Company as of December
+31, 2004 and 2003, and the related consolidated statements of
+operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31,
+2004 of Callon Petroleum Company and our report dated March 8, 2005, expressed an unqualified
+opinion thereon.
+/s/Ernst & Young LLP
+New Orleans, Louisiana 
+March 8, 2005
+82
+Table of Contents 
+ITEM 9.B OTHER INFORMATION 
+We have disclosed all information required to be disclosed in a current report on Form 8-K during
+the fourth quarter of the year ended December 31, 2004 in previously filed reports on Form 8-K.
+83
+Table of Contents 
+PART III. 
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. 
+For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 5, 2005 which will be filed with the
+Securities and Exchange Commission and is incorporated herein by reference.
+ITEM 11. EXECUTIVE COMPENSATION. 
+For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 5, 2005 which will be filed with the
+Securities and Exchange Commission and is incorporated herein by reference.
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS. 
+For information concerning the security ownership of certain beneficial owners and management, see
+the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of
+Stockholders on May 5, 2005 which will be filed with the Securities and Exchange Commission and is
+incorporated herein by reference.
+84
+Table of Contents 
+Equity Compensation Plan Information 
+The following table provides information as of December 31, 2004 regarding the number of shares of
+Common Stock that may be issued under the Company’s equity compensation plans.
+Number of securities 
+remaining available for 
+future issuance under 
+Number of securities to 
+Weighted-average 
+equity compensation 
+be issued upon exercise 
+exercise price of 
+plans (excluding 
+of outstanding options, 
+outstanding options, 
+securities reflected in 
+warrants and rights 
+warrants and rights 
+column (a)) 
+Plan Category 
+(a) 
+(b) 
+(c) 
+Equity compensation
+plans approved by
+security holders 
+1,370,266 
+$ 
+10.51 
+501,726 
+Equity compensation
+plans not
+approved by
+security holders 
+142,333 
+$ 
+4.36 
+65,666 
+Total 
+1,512,599 
+$ 
+9.93 
+567,392 
+See Note 12 to the Consolidated Financial Statements for a description of the material provisions
+of each equity compensation plan under which our equity securities are authorized for issuance that
+was adopted without the approval of shareholders.
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 5, 2005 which will be filed with the
+Securities and Exchange Commission and is incorporated herein by reference.
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES. 
+For information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 5, 2005 which will be filed with the
+Securities and Exchange Commission and is incorporated herein by reference.
+85
+Table of Contents 
+PART IV. 
+ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 
+(a) 1. The following is an index to the financial statements and financial statement schedules
+that are filed as part of this Form 10-K on pages 44 through 79.
+Report of Independent Registered Public Accounting Firm
+Consolidated Balance Sheets as of the Years Ended December 31, 2004 and 2003
+Consolidated Statements of Operations for the Three Years in the Period Ended December 31, 2004
+Consolidated Statements of Stockholders’ Equity for the Three Years in the Period Ended December 31, 2004
+Consolidated Statements of Cash Flows for the Three Years in the Period Ended December 31, 2004
+Notes to Consolidated Financial Statements
+(a) 2. Schedules other than those listed above are omitted because they are not required, not
+applicable or the required information is included in the financial statements or notes thereto.
+(a) 3. Exhibits:
+2. 
+Plan of acquisition, reorganization, arrangement, liquidation or succession* 
+3. 
+Articles of Incorporation and Bylaws 
+3.1 
+Certificate of Incorporation of the Company, as amended (incorporated by
+reference to Exhibit 3.1 of the Company’s Annual Report on Form 10-K for the year
+ended December 31, 2003, File No. 001-14039) 
+3.2 
+Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the
+Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg. No.
+33-82408) 
+3.3 
+Certificate of Amendment to Certificate of Incorporation of the Company
+(incorporated by reference to Exhibit 3.3 of the Company’s Annual Report on Form
+10-K for the year ended December 31, 2003, File No. 001-14039) 
+4. 
+Instruments defining the rights of security holders, including indentures 
+4.1 
+Specimen Common Stock Certificate (incorporated by reference from Exhibit
+4.1 of the Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg.
+No. 33-82408) 
+86
+Table of Contents 
+4.2 
+Specimen Preferred Stock Certificate (incorporated by reference from
+Exhibit 4.2 of the Company’s Registration Statement on Form S-1, filed November 13,
+1995, Reg. No. 33-96700) 
+4.3 
+Designation for Convertible, Exchangeable Preferred Stock, Series A as
+corrected (included as part of Exhibit 3.1) 
+4.4 
+Indenture for Convertible Debentures (incorporated by reference from
+Exhibit 4.4 of the Company’s Registration Statement on Form S-1, filed
+November 13, 1995, Reg. No. 33-96700 
+4.5 
+Rights Agreement between Callon Petroleum Company and American Stock Transfer
+& Trust Company, Rights Agent, dated March 30, 2000 (incorporated by reference from
+Exhibit 99.1 of the Company’s Registration Statement on Form 8-A, filed April 6, 2000,
+File No. 001-14039) 
+4.6 
+Warrant dated as of June 29, 2001 entitling Duke Capital Partners, LLC to purchase
+common stock from the Company. (incorporated by reference to Exhibit 4.11 of the
+Company’s Quarterly Report on Form 10-Q for the period ended June 30,
+2001, File No. 001-14039) 
+4.7 
+Form of Warrant entitling certain holders of the Company’s 10.125% Senior Subordinated
+Notes due 2002 to purchase common stock from the Company (incorporated by reference to
+Exhibit 4.13 of the Company’s Form 10-Q for the period ended June 30, 2002, File No. 001-
+14039) 
+4.8 
+Form of Warrants dated December 8, 2003 and December 29, 2003 entitling lenders under
+the Company’s $185 million amended and restated senior unsecured credit agreement dated
+December 23, 2003 to purchase common stock from the Company (incorporated by reference to Exhibit 4.14 of the Company’s Annual Report on Form 10-K for
+the year ended December 31, 2003, File No. 001-14039) 
+4.9 
+Indenture for the Company’s 9.75% Senior Notes due 2010, dated March 15, 2004 between
+Callon Petroleum Company and American Stock Transfer and Trust Company (incorporated by
+reference to Exhibit 4.16 of the Company’s Quarterly Report on Form 10-Q for the period
+ended March 31, 2004, File No. 001-14039) 
+9. 
+Voting trust agreement 
+None. 
+10. 
+Material contracts 
+10.1 
+Registration Rights Agreement dated September 16, 1994 between the Company
+and NOCO Enterprises, L. P. (incorporated by reference from Exhibit 10.2 of the
+Company’s Registration Statement on Form 8-B filed October 3,
+1994) 
+10.2 
+Counterpart to Registration Rights Agreement by and between the Company,
+Ganger Rolf ASA and Bonheur ASA. (incorporated by reference from Exhibit 10.2
+of the Company’s Report on Form 10-K for the fiscal year ended December 31,
+2000, File No. 001-14039) 
+87
+Table of Contents 
+10.3 
+Registration Rights Agreement dated September 16, 1994 between the Company
+and Callon Stockholders (incorporated by reference from Exhibit 10.3 of the Company’s
+Registration Statement on Form 8-B filed October 3, 1994) 
+10.4 
+Callon Petroleum Company 1994 Stock Incentive Plan (incorporated by
+reference from Exhibit 10.5 of the Company’s Registration Statement on Form 8-B filed
+October 3, 1994) 
+10.5 
+Purchase and Sale Agreement between Callon Petroleum Operating Company and
+Murphy Exploration Company, dated May 26, 1999 (incorporated by reference from
+Exhibit 10.11 on Form S-2, filed June 14, 1999, Reg. No. 333-80579) 
+10.6 
+Callon Petroleum Company 1996 Stock Incentive Plan as amended on May 9, 2000
+(incorporated by reference from Appendix I of the Company’s Definitive
+Proxy Statement of Schedule 14A filed March 28, 2000) 
+10.7 
+Conveyance of Overriding Royalty Interest from the Company to Duke Capital
+Partners, LLC, dated June 29, 2001 (incorporated by reference to Exhibit 10.03 of the
+Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2001, File No.
+001-14039) 
+10.8 
+Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference to
+Exhibit 10.13 of the Company’s Annual Report on Form 10-K for the year ended December 31,
+2001, File No. 001-14039) 
+10.9 
+Change of Control Severance Compensation Agreement by and between Callon Petroleum
+and John S. Weatherly dated January 1, 2002 (incorporated by reference to
+Exhibit 10.14 of the Company’s Annual Report on Form 10-K for the year ended
+December 31, 2001, File No. 001-14039) 
+10.10 
+Change of Control Severance Compensation Agreement by and between Callon Petroleum
+Company and Fred L. Callon, dated January 1, 2002 (incorporated by reference to
+Exhibit 10.15 of the Company’s Annual Report on Form 10-K for the year
+ended December 31, 2001, File No. 001-14039) 
+10.11 
+Change of Control Severance Compensation Agreement by and between Callon Petroleum
+and Dennis W. Christian, dated January 1, 2002 (incorporated by reference to
+Exhibit 10.16 of the Company’s Annual Report on Form 10-K for the year ended
+December 31, 2001, File No. 001-14039) 
+10.12 
+Medusa Spar Agreement dated as of August 8, 2003, among Callon Petroleum Operating
+Company, Murphy Exploration & Production Company-USA and Oceaneering
+International, Inc. (incorporated by reference to Exhibit 10.19 of the Company’s Annual Report on Form 10-K for
+the year ended December 31, 2003, File No. 001-14039) 
+10.13 
+Credit Agreement dated as of December 18, 2003 among Medusa Spar LLC, The Bank of
+Nova Scotia, as Administrative Agent, Bank One, N.A., Sun Trust Bank, as
+Syndication Agents and other Lenders Party. (incorporated by reference to Exhibit 10.20 of the Company’s Annual Report on Form 10-K for
+the year ended December 31, 2003, File No. 001-14039) 
+88
+Table of Contents 
+10.14 
+The Retirement Package and Release Agreement made, entered into and effective March
+9, 2004 between Callon Petroleum Company and Dennis W. Christian. (incorporated by reference to Exhibit 10.21 of the Company’s Annual Report on Form 10-K for
+the year ended December 31, 2003, File No. 001-14039) 
+10.15 
+The Retirement Package and Release Agreement made, entered into and effective March
+9, 2004 between Callon Petroleum Company and Kathy G. Tilley. (incorporated by reference to Exhibit 10.22 of the Company’s Annual Report on Form 10-K for
+the year ended December 31, 2003, File No. 001-14039) 
+10.16 
+Credit Agreement dated as of June 14, 2004 between the Company and Union Bank of
+California, N.A., as Administrative Agent (incorporated by reference to
+Exhibit 10.1 of the Company’s Current Report on Form 8-K dated June 14, 2004,
+File No. 001-14039) 
+11. 
+Statement re computation of per share earnings* 
+12. 
+Statements re computation of ratios* 
+13. 
+Annual Report to security holders, Form 10-Q or quarterly reports* 
+14. 
+Code of Ethics 
+14.1 
+Code of Ethics for Chief Executive Officers and Senior Financial Officers
+(incorporated by reference to Exhibit 14.1 of the Company’s Annual report on
+Form 10-K for the year ended December 31, 2003, File No. 001-14039) 
+16. 
+Letter re change in certifying accountant* 
+18. 
+Letter re change in accounting principles* 
+21. 
+Subsidiaries of the Company 
+21.1 
+Subsidiaries of the Company (incorporated by reference from Exhibit 21.1 of
+the Company’s Registration Statement on Form 8-B filed October 3, 1994) 
+22. 
+Published report regarding matters submitted to vote of security holders* 
+23. 
+Consents of experts and counsel 
+23.1 
+Consent of Ernst & Young LLP 
+23.2 
+Consent of Huddleston & Co., Inc. 
+24. 
+Power of attorney* 
+31. 
+Rule 13a-14(a) Certifications 
+31.1 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) 
+31.2 
+Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) 
+89
+Table of Contents 
+32. 
+Section 1350 Certifications 
+32.1 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(b) 
+32.2 
+Certification of Chief Financial Officer pursuant to Rule 13(a)-14(b) 
+99. 
+Additional Exhibits* 
+*Inapplicable to this filing. 
+90
+Table of Contents 
+SIGNATURES 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed
+below by the following persons on behalf of the registrant and in the capacities and on the dates
+indicated.
+CALLON PETROLEUM COMPANY
+Date: March 10, 2005 
+/s/Fred L. Callon
+Fred L. Callon (principal executive officer, director) 
+Date: March 10, 2005 
+/s/John S. Weatherly
+John S. Weatherly (principal financial officer) 
+Date: March 10, 2005 
+/s/Rodger W. Smith
+Rodger W. Smith (principal accounting officer) 
+Date: March 10, 2005 
+/s/John S. Callon
+John S. Callon (director) 
+Date: March 10, 2005 
+/s/Richard Flury
+Richard Flury (director) 
+Date: March 10, 2005 
+/s/Robert A. Stanger
+Robert A. Stanger (director) 
+Date: March 10, 2005 
+/s/John C. Wallace
+John C. Wallace (director) 
+Date: March 10, 2005 
+/s/B. F. Weatherly
+B. F. Weatherly (director) 
+Date: March 10, 2005 
+/s/Richard O. Wilson
+Richard O. Wilson (director) 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
+registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
+duly authorized.
+CALLON PETROLEUM COMPANY 
+Date: March 10, 2005 
+By: 
+/s/John S. Weatherly
+John S. Weatherly, Senior Vice President and 
+Chief Financial Officer 
+91
+Table of Contents 
+EXHIBIT INDEX 
+2. 
+Plan of acquisition, reorganization, arrangement, liquidation or succession* 
+3. 
+Articles of Incorporation and Bylaws 
+3.1 
+Certificate of Incorporation of the Company, as amended (incorporated by
+reference to Exhibit 3.1 of the Company’s Annual Report on Form 10-K for the year
+ended December 31, 2003, File No. 001-14039) 
+3.2 
+Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the
+Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg. No.
+33-82408) 
+3.3 
+Certificate of Amendment to Certificate of Incorporation of the Company
+(incorporated by reference to Exhibit 3.3 of the Company’s Annual Report on Form
+10-K for the year ended December 31, 2003, File No. 001-14039) 
+4. 
+Instruments defining the rights of security holders, including indentures 
+4.1 
+Specimen Common Stock Certificate (incorporated by reference from Exhibit
+4.1 of the Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg.
+No. 33-82408) 
+4.2 
+Specimen Preferred Stock Certificate (incorporated by reference from
+Exhibit 4.2 of the Company’s Registration Statement on Form S-1, filed November 13,
+1995, Reg. No. 33-96700) 
+4.3 
+Designation for Convertible, Exchangeable Preferred Stock, Series A as
+corrected (included as part of Exhibit 3.1) 
+4.4 
+Indenture for Convertible Debentures (incorporated by reference from
+Exhibit 4.4 of the Company’s Registration Statement on Form S-1, filed
+November 13, 1995, Reg. No. 33-96700 
+4.5 
+Rights Agreement between Callon Petroleum Company and American Stock Transfer
+& Trust Company, Rights Agent, dated March 30, 2000 (incorporated by reference from
+Exhibit 99.1 of the Company’s Registration Statement on Form 8-A, filed April 6, 2000,
+File No. 001-14039) 
+4.6 
+Warrant dated as of June 29, 2001 entitling Duke Capital Partners, LLC to purchase
+common stock from the Company. (incorporated by reference to Exhibit 4.11 of the
+Company’s Quarterly Report on Form 10-Q for the period ended June 30,
+2001, File No. 001-14039) 
+4.7 
+Form of Warrant entitling certain holders of the Company’s 10.125% Senior Subordinated
+Notes due 2002 to purchase common stock from the Company (incorporated by reference to
+Exhibit 4.13 of the Company’s Form 10-Q for the period ended June 30, 2002, File No. 001-
+14039) 
+4.8 
+Form of Warrants dated December 8, 2003 and December 29, 2003 entitling lenders under
+the Company’s $185 million amended and restated senior unsecured credit agreement dated
+December 23, 2003 to purchase common stock from the Company (incorporated by reference to Exhibit 4.14 of the Company’s Annual Report on Form 10-K for
+the year ended December 31, 2003, File No. 001-14039) 
+4.9 
+Indenture for the Company’s 9.75% Senior Notes due 2010, dated March 15, 2004 between
+Callon Petroleum Company and American Stock Transfer and Trust Company (incorporated by
+reference to Exhibit 4.16 of the Company’s Quarterly Report on Form 10-Q for the period
+ended March 31, 2004, File No. 001-14039) 
+Table of Contents 
+9. 
+Voting trust agreement 
+None. 
+10. 
+Material contracts 
+10.1 
+Registration Rights Agreement dated September 16, 1994 between the Company
+and NOCO Enterprises, L. P. (incorporated by reference from Exhibit 10.2 of the
+Company’s Registration Statement on Form 8-B filed October 3,
+1994) 
+10.2 
+Counterpart to Registration Rights Agreement by and between the Company,
+Ganger Rolf ASA and Bonheur ASA. (incorporated by reference from Exhibit 10.2
+of the Company’s Report on Form 10-K for the fiscal year ended December 31,
+2000, File No. 001-14039) 
+10.3 
+Registration Rights Agreement dated September 16, 1994 between the Company
+and Callon Stockholders (incorporated by reference from Exhibit 10.3 of the Company’s
+Registration Statement on Form 8-B filed October 3, 1994) 
+10.4 
+Callon Petroleum Company 1994 Stock Incentive Plan (incorporated by
+reference from Exhibit 10.5 of the Company’s Registration Statement on Form 8-B filed
+October 3, 1994) 
+10.5 
+Purchase and Sale Agreement between Callon Petroleum Operating Company and
+Murphy Exploration Company, dated May 26, 1999 (incorporated by reference from
+Exhibit 10.11 on Form S-2, filed June 14, 1999, Reg. No. 333-80579) 
+10.6 
+Callon Petroleum Company 1996 Stock Incentive Plan as amended on May 9, 2000
+(incorporated by reference from Appendix I of the Company’s Definitive
+Proxy Statement of Schedule 14A filed March 28, 2000) 
+10.7 
+Conveyance of Overriding Royalty Interest from the Company to Duke Capital
+Partners, LLC, dated June 29, 2001 (incorporated by reference to Exhibit 10.03 of the
+Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2001, File No.
+001-14039) 
+10.8 
+Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference to
+Exhibit 10.13 of the Company’s Annual Report on Form 10-K for the year ended December 31,
+2001, File No. 001-14039) 
+10.9 
+Change of Control Severance Compensation Agreement by and between Callon Petroleum
+and John S. Weatherly dated January 1, 2002 (incorporated by reference to
+Exhibit 10.14 of the Company’s Annual Report on Form 10-K for the year ended
+December 31, 2001, File No. 001-14039) 
+10.10 
+Change of Control Severance Compensation Agreement by and between Callon Petroleum
+Company and Fred L. Callon, dated January 1, 2002 (incorporated by reference to
+Exhibit 10.15 of the Company’s Annual Report on Form 10-K for the year
+ended December 31, 2001, File No. 001-14039) 
+10.11 
+Change of Control Severance Compensation Agreement by and between Callon Petroleum
+and Dennis W. Christian, dated January 1, 2002 (incorporated by reference to
+Exhibit 10.16 of the Company’s Annual Report on Form 10-K for the year ended
+December 31, 2001, File No. 001-14039) 
+10.12 
+Medusa Spar Agreement dated as of August 8, 2003, among Callon Petroleum Operating
+Company, Murphy Exploration & Production Company-USA and Oceaneering
+International, Inc. (incorporated by reference to Exhibit 10.19 of the Company’s Annual Report on Form 10-K for
+the year ended December 31, 2003, File No. 001-14039) 
+10.13 
+Credit Agreement dated as of December 18, 2003 among Medusa Spar LLC, The Bank of
+Nova Scotia, as Administrative Agent, Bank One, N.A., Sun Trust Bank, as
+Syndication Agents and other Lenders Party. (incorporated by reference to Exhibit 10.20 of the Company’s Annual Report on Form 10-K for
+the year ended December 31, 2003, File No. 001-14039) 
+10.14 
+The Retirement Package and Release Agreement made, entered into and effective March
+9, 2004 between Callon Petroleum Company and Dennis W. Christian. (incorporated by reference to Exhibit 10.21 of the Company’s Annual Report on Form 10-K for
+the year ended December 31, 2003, File No. 001-14039) 
+10.15 
+The Retirement Package and Release Agreement made, entered into and effective March
+9, 2004 between Callon Petroleum Company and Kathy G. Tilley. (incorporated by reference to Exhibit 10.22 of the Company’s Annual Report on Form 10-K for
+the year ended December 31, 2003, File No. 001-14039) 
+10.16 
+Credit Agreement dated as of June 14, 2004 between the Company and Union Bank of
+California, N.A., as Administrative Agent (incorporated by reference to
+Exhibit 10.1 of the Company’s Current Report on Form 8-K dated June 14, 2004,
+File No. 001-14039) 
+Table of Contents 
+11. 
+Statement re computation of per share earnings* 
+12. 
+Statements re computation of ratios* 
+13. 
+Annual Report to security holders, Form 10-Q or quarterly reports* 
+14. 
+Code of Ethics 
+14.1 
+Code of Ethics for Chief Executive Officers and Senior Financial Officers
+(incorporated by reference to Exhibit 14.1 of the Company’s Annual report on
+Form 10-K for the year ended December 31, 2003, File No. 001-14039) 
+16. 
+Letter re change in certifying accountant* 
+18. 
+Letter re change in accounting principles* 
+21. 
+Subsidiaries of the Company 
+21.1 
+Subsidiaries of the Company (incorporated by reference from Exhibit 21.1 of
+the Company’s Registration Statement on Form 8-B filed October 3, 1994) 
+22. 
+Published report regarding matters submitted to vote of security holders* 
+23. 
+Consents of experts and counsel 
+23.1 
+Consent of Ernst & Young LLP 
+23.2 
+Consent of Huddleston & Co., Inc. 
+24. 
+Power of attorney* 
+31. 
+Rule 13a-14(a) Certifications 
+31.1 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) 
+31.2 
+Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) 
+32. 
+Section 1350 Certifications 
+32.1 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(b) 
+32.2 
+Certification of Chief Financial Officer pursuant to Rule 13(a)-14(b) 
+99. 
+Additional Exhibits* 
+*Inapplicable to this filing.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2004/0000950134-05-004630/filing_metadata.csv b/raw/filings/0000928022/2004/0000950134-05-004630/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..c20b5eaa115cb938ac199bee64606f927e6bb19e
--- /dev/null
+++ b/raw/filings/0000928022/2004/0000950134-05-004630/filing_metadata.csv
@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000928022,CPE,Callon Petroleum Co,10-K,2005-03-10,2004-12-31,2005-03-10T22:19:19.000Z,0000950134-05-004630,d23168e10vk.htm,FORM 10-K,924582,0,0,https://www.sec.gov/Archives/edgar/data/928022/000095013405004630/d23168e10vk.htm,https://www.sec.gov/Archives/edgar/data/928022/000095013405004630/,2004,2004,1
diff --git a/raw/filings/0000928022/2004/0000950134-05-004630/item1.txt b/raw/filings/0000928022/2004/0000950134-05-004630/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..5b00418841c102a5e9d7f182535a4d211a6c8f45
--- /dev/null
+++ b/raw/filings/0000928022/2004/0000950134-05-004630/item1.txt
@@ -0,0 +1,6428 @@
+ITEM 1 and 2. BUSINESS and PROPERTIES 
+Overview 
+Callon Petroleum Company has been engaged in the exploration, development, acquisition and
+production of oil and gas properties since 1950. Our properties are geographically
+concentrated primarily offshore in the Gulf of Mexico and onshore in Louisiana and Alabama. We
+were incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of
+a publicly traded limited partnership, a joint venture with a consortium of European investors and
+an independent energy company owned by members of current management. As used herein, the
+“Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors
+and subsidiaries unless the context requires otherwise.
+In 1989, we began increasing our reserves through the acquisition of producing properties that were
+geologically complex, had (or were analogous to fields with) an established production history from
+stacked pay zones and were candidates for exploitation. We focused on reducing operating costs and
+implementing production enhancements through the application of technologically advanced production
+and recompletion techniques.
+Over the past nine years, we have also placed emphasis on the acquisition of acreage with
+exploration and development drilling opportunities in the Gulf of Mexico shelf and deepwater areas.
+At December 31, 2004, we owned working interests in a total of 72 blocks/leases covering 145,000
+net acres. To minimize risk we join with industry partners to explore federal offshore blocks
+acquired in the Gulf of Mexico. We perform extensive geological and geophysical studies using
+computer-aided exploration techniques (CAEX), including, where appropriate, the acquisition of 3-D
+seismic or high-resolution 2-D data to facilitate these efforts. We continue to develop prospects
+on the shelf through our 3-D seismic partnership using Amplitude versus Offset (“AVO”) technology.
+In 1998, we began exploration in the Gulf of Mexico deepwater area (generally 900 to 5,500 feet of
+water) and during the fourth quarter of 2003, our first two deepwater projects, the Medusa and
+Habanero fields, began production. Please see “Significant Properties” for a more detailed
+discussion.
+We ended the year 2004 with estimated net proved reserves of 191 billion cubic feet of natural gas
+equivalent (“Bcfe”). This represents a decrease of 12% from 2003 year-end estimated net proved
+reserves of 217 Bcfe.
+The major focus of our future operations is expected to continue to be the exploration for and
+development of oil and gas properties, primarily in the Gulf of Mexico.
+Availability of Reports 
+All of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
+8-K, and amendments to such reports as well as other filings we make pursuant to Section 13(a) and
+15(d) of the Securities Exchange Act of 1934 are available free of charge on our Internet website.
+The address of our Internet website is www.callon.com. Our Securities and Exchange Commission
+(“SEC”) filings are available on our website as soon as they are posted to the EDGAR database on
+the SEC’s website.
+2
+Table of Contents 
+Business Strategy 
+Our goal is to increase shareholder value by increasing our reserves, production, cash flow and
+earnings. We seek to achieve these goals through the following strategies:
+• 
+focus on Gulf of Mexico exploration with a balance between shelf and deepwater areas
+using the latest available technology; 
+• 
+aggressively explore our existing prospect inventory; and 
+• 
+replenish our prospect inventory with increasing emphasis on prospect generation using
+AVO technology. 
+Exploration and Development Activities 
+Capital expenditures for exploration and development costs related to oil and gas properties
+totaled approximately $65 million in 2004. We incurred approximately $19 million in the Gulf of
+Mexico deepwater area primarily for continued development costs at our Habanero and Medusa
+discoveries and drilling of two satellite wells in the Medusa area. Interest of approximately $5
+million and general and administrative costs allocable directly to exploration and development
+projects of $7 million were capitalized in 2004. Our Gulf of Mexico shelf area expenditures account
+for the remainder of the total capital expended, which includes the developmental drilling and
+completion of a shallow miocene well and a shelf well and the drilling of six exploratory shelf
+wells, one of which was completed in 2004. Two are scheduled for completion during early 2005.
+Risk Factors 
+A decrease in oil and gas prices may adversely affect our results of operations and financial
+condition . Our success is highly dependent on prices for oil and gas, which are extremely volatile.
+Any substantial or extended decline in the price of oil or gas would have a material adverse effect
+on us. Oil and gas markets are both seasonal and cyclical. The prices of oil and gas depend on
+factors we cannot control such as weather, economic conditions, and levels of production, actions
+by OPEC and other countries and government actions. Prices of oil and gas will affect the following
+aspects of our business:
+• 
+our revenues, cash flows and earnings; 
+• 
+the amount of oil and gas that we are economically able to produce; 
+• 
+our ability to attract capital to finance our operations and the cost of the capital; 
+• 
+the amount we are allowed to borrow under our senior secured credit facility; 
+• 
+the value of our oil and gas properties; and 
+• 
+the profit or loss we incur in exploring for and developing our reserves. 
+3
+Table of Contents 
+Our reserve information represents estimates that may turn out to be incorrect if the assumptions
+upon which these estimates are based are inaccurate. Any material inaccuracies in these reserve
+estimates or underlying assumptions will materially affect the quantities and present value of our
+reserves. The process of estimating oil and gas reserves is complex. It requires interpretations
+of available technical data and various assumptions, including assumptions relating to economic
+factors. Any significant inaccuracies in these interpretations or assumptions could materially
+affect the estimated quantities and present value of reserves shown in this annual report.
+In order to prepare these estimates, we must project production rates and the timing of development
+expenditures. The assumptions regarding the timing and costs to commence production from our
+deepwater wells used in preparing our reserves are often subject to revisions over time as
+described under “Our deepwater operations have special operational risks that may negatively affect
+the value of those assets.” We must also analyze available geological, geophysical, production and
+engineering data, the extent, quality and reliability of which can vary. The process also requires
+us to make economic assumptions, such as oil and gas prices, drilling and operating expenses,
+capital expenditures, taxes and availability of funds. Therefore, estimates of oil and gas
+reserves are inherently imprecise.
+Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating
+expenses and quantities of recoverable oil and gas reserves most likely will vary from our
+estimates. Any significant variance could materially affect the estimated quantities and present
+value of reserves shown in this report. In addition, we may adjust estimates of proved reserves to
+reflect production history, results of exploration and development, prevailing oil and gas prices
+and other factors, many of which are beyond our control.
+You should not assume that the present value of future net cash flows from our proved reserves
+referred to in this report is the current market value of our estimated oil and gas reserves. In
+accordance with SEC requirements, we generally base the estimated discounted future net cash flows
+from our proved reserves on prices and costs on the date of the estimate. Actual future prices and
+costs may differ materially from those used in the present value estimate.
+Information about reserves constitutes forward-looking information. See “Forward-Looking
+Statements” for information regarding forward-looking information. The discounted present value of
+our oil and gas reserves is prepared in accordance with guidelines established by the SEC. A
+purchaser of reserves would use numerous other factors to value our reserves. The discounted
+present value of reserves, therefore, does not represent the fair market value of those reserves.
+On December 31, 2004, approximately 44% of the discounted present value of our estimated net proved
+reserves were proved undeveloped. Proved undeveloped reserves represented 50% of total proved
+reserves. Substantially all of these proved undeveloped reserves were attributable to our deepwater
+properties. Development of these properties is subject to additional risks as described above.
+Unless we are able to replace reserves which we have produced, our cash flows and production will
+decrease over time. Our future success depends upon our ability to find, develop and acquire oil
+and gas reserves that are economically recoverable. As is generally the case for Gulf properties,
+our producing properties usually have high initial production rates, followed by a steep decline in
+production. As a result, we must continually locate and develop or acquire new oil and gas reserves
+to replace those being depleted by production. We must do this even during periods of low oil and
+gas prices when it is difficult to raise the capital necessary to finance these activities and
+during periods of high operating costs when it
+4
+Table of Contents 
+is expensive to contract for drilling rigs and other
+equipment and personnel necessary to explore for oil
+and gas. Without successful exploration or acquisition activities, our reserves, production and
+revenues will decline rapidly. We cannot assure you that we will be able to find and develop or
+acquire additional reserves at an acceptable cost.
+A significant part of the value of our production and reserves is concentrated in a small number of
+offshore properties, and any production problems or inaccuracies in reserve estimates related to
+those properties would adversely impact our business. During 2004, 83% of our daily production
+came from four of our properties in the Gulf of Mexico. Moreover, one property accounted for 34% of
+our production during this period. In addition, at December 31, 2004, most of our proved reserves
+were located in three fields in the Gulf of Mexico, with approximately 82% of our total net proved
+reserves attributable to these properties. If mechanical problems, storms or other events
+curtailed a substantial portion of this production or if the actual reserves associated with any
+one of these producing properties are less than our estimated reserves, our results of operations
+and financial condition could be adversely affected.
+Our focus on exploration projects increases the risks inherent in our oil and gas activities. Our
+business strategy focuses on replacing reserves through exploration, where the risks are greater
+than in acquisitions and development drilling. Although we have been successful in exploration in
+the past, we cannot assure you that we will continue to increase reserves through exploration or at
+an acceptable cost. Additionally, we are often uncertain as to the future costs and timing of
+drilling, completing and producing wells. Our drilling operations may be curtailed, delayed or
+canceled as a result of a variety of factors, including:
+• 
+unexpected drilling conditions; 
+• 
+pressure or inequalities in formations; 
+• 
+equipment failures or accidents; 
+• 
+adverse weather conditions; 
+• 
+compliance with governmental requirements; and 
+• 
+shortages or delays in the availability of drilling rigs and the delivery of equipment. 
+We do not operate all of our properties and have limited influence over the operations of some of
+these properties, particularly our deepwater properties. Our lack of control could result in the
+following:
+• 
+the operator may initiate exploration or development on a faster or slower pace than we
+prefer; 
+• 
+the operator may propose to drill more wells or build more facilities on a project than
+we have funds for or that we deem appropriate, which may mean that we are unable to
+participate in the project or share in the revenues generated by the project even though we
+paid our share of exploration costs; and 
+• 
+if an operator refuses to initiate a project, we may be unable to pursue the project. 
+Any of these events could materially reduce the value of our properties.
+Our deepwater operations have special operational risks that may negatively affect the value of
+those assets. Drilling operations in the deepwater area are by their nature more difficult and
+costly than drilling operations in shallow water. Deepwater drilling operations require the
+application of more advanced drilling technologies involving a higher risk of technological failure
+and usually have significantly higher drilling costs than shallow water drilling operations.
+Deepwater wells are completed
+5
+Table of Contents 
+using sub-sea completion techniques that require substantial time and
+the use of advanced remote installation equipment. These operations involve a high risk of mechanical difficulties and
+equipment failures that could result in significant cost overruns.
+In deepwater, the time required to commence production following a discovery is much longer than in
+shallow water and on-shore. Deepwater discoveries require the construction of expensive production
+facilities and pipelines prior to production. We cannot estimate the costs and timing of the
+construction of these facilities with certainty, and the accuracy of our estimates will be affected
+by a number of factors beyond our control, including the following:
+• 
+decisions made by the operators of our deepwater wells; 
+• 
+the availability of materials necessary to construct the facilities; 
+• 
+the proximity of our discoveries to pipelines; and 
+• 
+the price of oil and natural gas. 
+Delays and cost overruns in the commencement of production will affect the value of our deepwater
+prospects and the discounted present value of reserves attributable to those prospects.
+Competitive industry conditions may negatively affect our ability to conduct operations. We
+operate in the highly competitive areas of oil and gas exploration, development and production. We
+compete for the purchase of leases in the Gulf of Mexico from the U. S. government and from other
+oil and gas companies. These leases include exploration prospects as well as properties with
+proved reserves. Factors that affect our ability to compete in the marketplace include:
+• 
+our access to the capital necessary to drill wells and acquire properties; 
+• 
+our ability to acquire and analyze seismic, geological and other information relating to
+a property; 
+• 
+our ability to retain the personnel necessary to properly evaluate seismic and other
+information relating to a property; 
+• 
+the location of, and our ability to access, platforms, pipelines and other facilities
+used to produce and transport oil and gas production; 
+• 
+the standards we establish for the minimum projected return on an investment of our
+capital; and 
+• 
+the availability of alternate fuel sources. 
+Our competitors include major integrated oil companies, substantial independent energy companies,
+and affiliates of major interstate and intrastate pipelines and national and local gas gatherers,
+many of which possess greater financial, technological and other resources than we do.
+Our competitors may use superior technology, which we may be unable to afford or which would
+require costly investment by us in order to compete. Our industry is subject to rapid and
+significant advancements in technology, including the introduction of new products and services
+using new technologies. As our competitors use or develop new technologies, we may be placed at a
+competitive disadvantage, and competitive pressures may force us to implement new technologies at a
+substantial cost. In addition, our competitors may have greater financial, technical and personnel
+resources that allow them to enjoy technological advantages and may in the future allow them to
+implement new technologies before we can. We cannot be certain that we will be able to implement
+technologies on a timely basis or at a cost that is acceptable to us. One or more of the
+technologies that we currently use or that we may implement in the future may become obsolete, and
+we may be adversely affected. For example, marine seismic acquisition technology has been
+characterized by rapid technological advancements in recent years, and further significant
+technological developments could substantially impair our 3-D seismic data’s value.
+6
+Table of Contents 
+We may not be able to replace our reserves or generate cash flows if we are unable to raise
+capital. We will be required to make substantial capital expenditures to develop our existing
+reserves, and to discover new oil and gas reserves. Historically, we have financed these
+expenditures primarily with cash from operations, proceeds from bank borrowings and proceeds from
+the sale of debt and equity securities. See “Management’s Discussion and Analysis of Financial
+Condition and Results of Operations ¾ Liquidity and Capital Resources” for a discussion of
+our capital budget. We cannot assure you that we will be able to raise capital in the future. We
+also make offers to acquire oil and gas properties in the ordinary course of our business. If these
+offers are accepted, our capital needs may increase substantially.
+We expect to continue using our senior secured credit facility to borrow funds to supplement our
+available cash. The amount we may borrow under our senior secured credit facility may not exceed a
+borrowing base determined by the lenders under such facility based on their projections of our
+future production, production costs, taxes, commodity prices and any other factors deemed relevant
+by our lenders. We cannot control the assumptions the lenders use to calculate our borrowing base.
+The lenders may, without our consent, adjust the borrowing base semiannually or in situations where
+we purchase or sell assets or issue debt securities. If our borrowings under the senior secured
+credit facility exceed the borrowing base, the lenders may require that we repay the excess. If
+this were to occur, we might have to sell assets or seek financing from other sources. Sales of
+assets could further reduce the amount of our borrowing base. We cannot assure you that we would be
+successful in selling assets or arranging substitute financing. If we were not able to repay
+borrowings under our senior secured credit facility to reduce the outstanding amount to less than
+the borrowing base, we would be in default under our senior secured credit facility. For a
+description of our senior secured credit facility and its principal terms and conditions, see
+“Management’s Discussion and Analysis of Financial Condition and Results of Operations
+¾ Liquidity and Capital Resources” and Note 5 to our Consolidated Financial Statements.
+Our decision to drill a prospect is subject to a number of factors and we may decide to alter our
+drilling schedule or not drill at all. A prospect is a property on which we have identified what
+our geoscientists believe, based on available seismic and geological information, to be indications
+of hydrocarbons. Our prospects are in various stages of evaluation, ranging from a prospect which
+is ready to drill to a prospect which will require substantial additional seismic data processing
+and interpretation. Whether we ultimately drill a prospect may depend on the following factors:
+• 
+receipt of additional seismic data or the reprocessing of existing data; 
+• 
+material changes in oil or gas prices; 
+• 
+the costs and availability of drilling rigs; 
+• 
+the success or failure of wells drilled in similar formations or which would use the
+same production facilities; 
+• 
+availability and cost of capital; 
+• 
+changes in the estimates of the costs to drill or complete wells; 
+• 
+our ability to attract other industry partners to acquire a portion of the working
+interest to reduce exposure to costs and drilling risks; and 
+• 
+decisions of our joint working interest owners. 
+We will continue to gather data about our prospects and it is possible that additional information
+may cause us to alter our drilling schedule or determine that a prospect should not be pursued at
+all. You should understand that our plans regarding our prospects are subject to change.
+7
+Table of Contents 
+Weather, unexpected subsurface conditions, and other unforeseen operating hazards may adversely
+impact our ability to conduct business. There are many operating hazards in exploring for and
+producing oil and gas, including:
+• 
+our drilling operations may encounter unexpected formations or pressures, which could
+cause damage to equipment or personal injury; 
+• 
+we may experience equipment failures which curtail or stop production; 
+• 
+we could experience blowouts or other damages to the productive formations that may
+require a well to be re-drilled or other corrective action to be taken; and 
+• 
+because of these or other events, we could experience environmental hazards, including
+oil spills, gas leaks, and ruptures. 
+In the event of any of the foregoing, we may be subject to interrupted production or substantial
+environmental liability due to injury to or loss of life, damage to or destruction of property,
+natural resources and equipment, pollution and other environmental damage, investigation and
+remediation requirements. Moreover, a substantial portion of our operations are offshore and are
+subject to a variety of risks peculiar to the marine environment such as capsizing, collisions,
+hurricanes and other adverse weather conditions. These conditions can cause substantial damage to
+facilities and interrupt production. Offshore operations are also subject to more extensive
+governmental regulation.
+We cannot assure you that we will be able to maintain adequate insurance at rates we consider
+reasonable to cover our possible losses from operating hazards. The occurrence of a significant
+event not fully insured or indemnified against could materially and adversely affect our financial
+condition and results of operations.
+We may not have production to offset hedges; by hedging, we may not benefit from price increases. 
+Part of our business strategy is to reduce our exposure to the volatility of oil and gas prices by
+hedging a portion of our production. In a typical hedge transaction, we will have the right to
+receive from the other parties to the hedge the excess of the fixed price specified in the hedge
+over a floating price based on a market index, multiplied by the quantity hedged. If the floating
+price exceeds the fixed price, we are required to pay the other parties this difference multiplied
+by the quantity hedged. We are required to pay the difference between the floating price and the
+fixed price when the floating price exceeds the fixed price regardless of whether we have
+sufficient production to cover the quantities specified in the hedge. Significant reductions in
+production at times when the floating price exceeds the fixed price could require us to make
+payments under the hedge agreements even though such payments are not offset by sales of
+production. Hedging will also prevent us from receiving the full advantage of increases in oil or
+gas prices above the fixed amount specified in the hedge. We also enter into price “collars” to
+reduce the risk of changes in oil and gas prices. Under a collar, no payments are due by either
+party so long as the market price is above a floor set in the collar and below a ceiling. If the
+price falls below the floor, the counter-party to the collar pays the difference to us and if the
+price is above the ceiling, we pay the counter-party
+the difference. Another type of hedging contract we have entered into is a put contract. Under a
+put, if the price falls below the set floor price, the counter-party to the contract pays the
+difference to us. See “Quantitative and Qualitative Disclosures About Market Risks” for a
+discussion of our hedging practices.
+Compliance with environmental and other government regulations could be costly and could negatively
+impact production. Our operations are subject to numerous laws and regulations governing the
+operation and maintenance of our facilities and the discharge of materials into the environment or
+otherwise relating to environmental protection. For a discussion of the material regulations
+applicable to
+8
+Table of Contents 
+us, see “Federal Regulations,” “State Regulations,” and “Environmental Regulations.”
+These laws and regulations may:
+• 
+require that we acquire permits before commencing drilling; 
+• 
+restrict the substances that can be released into the environment in connection with
+drilling and production activities; 
+• 
+limit or prohibit drilling activities on protected areas such as wetlands or wilderness
+areas; and 
+• 
+require remedial measures to mitigate pollution from former operations, such as
+dismantling abandoned production facilities. 
+Under these laws and regulations, we could be liable for personal injury and clean-up costs and
+other environmental and property damages, as well as administrative, civil and criminal penalties.
+We maintain limited insurance coverage for sudden and accidental environmental damages. We do not
+believe that insurance coverage for environmental damages that occur over time is available at a
+reasonable cost. Also, we do not believe that insurance coverage for the full potential liability
+that could be caused by sudden and accidental environmental damages is available at a reasonable
+cost. Accordingly, we may be subject to liability or we may be required to cease production from
+properties in the event of environmental damages.
+Factors beyond our control affect our ability to market production and our financial results. The
+ability to market oil and gas from our wells depends upon numerous factors beyond our control.
+These factors include:
+• 
+the extent of domestic production and imports of oil and gas; 
+• 
+the proximity of the gas production to gas pipelines; 
+• 
+the availability of pipeline capacity; 
+• 
+the demand for oil and gas by utilities and other end users; 
+• 
+the availability of alternative fuel sources; 
+• 
+the effects of inclement weather; 
+• 
+state and federal regulation of oil and gas marketing; and 
+• 
+federal regulation of gas sold or transported in interstate commerce. 
+Because of these factors, we may be unable to market all of the oil or gas we produce. In addition,
+we may be unable to obtain favorable prices for the oil and gas we produce.
+If oil and gas prices decrease, we may be required to take writedowns of the carrying value of our
+oil and gas properties. We may be required to writedown the carrying value of our oil and gas
+properties when oil and gas prices are low or if we have substantial downward adjustments to our
+estimated net proved reserves, increases in our estimates of development costs or deterioration in
+our exploration results. Under the full-cost method which we use to account for our oil and gas
+properties, the net capitalized costs of our oil and gas properties may not exceed the present
+value, discounted at 10%, of future net cash flows from estimated net proved reserves, using period end oil and gas prices or
+prices as of the date of our auditor’s report, plus the lower of cost or fair market value of our
+unproved properties. If net capitalized costs of our oil and gas properties exceed this limit, we
+must charge the amount of the excess to earnings. This type of charge will not affect our cash
+flows, but will reduce the book value of our stockholders’ equity. We review the carrying value of
+our properties quarterly, based on prices in effect as of the end of each quarter or at the time of
+reporting our results. Once incurred, a writedown of oil and gas properties is not reversible at a
+later date, even if prices increase.
+9
+Table of Contents 
+There are inherent limitations in all control systems, and misstatements due to error or fraud that
+could seriously harm our business may occur and not be detected. Our management, including our
+Chief Executive Officer and Chief Financial Officer, does not expect that our internal controls and
+disclosure controls will prevent all possible error and all fraud. A control system, no matter how
+well conceived and operated, can provide only reasonable, not absolute, assurance that the
+objectives of the control system are met. In addition, the design of a control system must reflect
+the fact that there are resource constraints and the benefit of controls must be relative to their
+costs. Because of the inherent limitations in all control systems, an
+evaluation of controls can only
+provide reasonable assurance that all material control issues and instances of fraud, if any, in our company
+have been detected. These inherent limitations include the realities that judgments in
+decision-making can be faulty and that breakdowns can occur because of simple error or mistake.
+Further, controls can be circumvented by the individual acts of some persons or by collusion of two
+or more persons. The design of any system of controls is based in part upon certain assumptions
+about the likelihood of future events, and there can be no assurance that any design will succeed
+in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system,
+misstatements due to error or fraud may occur and not be detected. A failure of our controls and
+procedures to detect error or fraud could seriously harm our business and results of operations.
+Forward-Looking Statements 
+In this report, we have made many forward-looking statements. We cannot assure you that the plans,
+intentions or expectations upon which our forward-looking statements are based will occur. Our
+forward-looking statements are subject to risks, uncertainties and assumptions, including those
+discussed elsewhere in this report. Forward-looking statements include statements regarding:
+• 
+our oil and gas reserve quantities, and the discounted present value of these
+reserves; 
+• 
+the amount and nature of our capital expenditures; 
+• 
+drilling of wells; 
+• 
+the timing and amount of future production and operating costs; 
+• 
+business strategies and plans of management; and 
+• 
+prospect development and property acquisitions. 
+Some of the risks, which could affect our future results and could cause results to differ
+materially from those expressed in our forward-looking statements, include:
+• 
+general economic conditions; 
+• 
+the volatility of oil and natural gas prices; 
+• 
+the uncertainty of estimates of oil and natural gas reserves; 
+• 
+the impact of competition; 
+• 
+the availability and cost of seismic, drilling and other equipment; 
+• 
+operating hazards inherent in the exploration for and production of oil and natural
+gas; 
+• 
+difficulties encountered during the exploration for and production of oil and
+natural gas; 
+• 
+difficulties encountered in delivering oil and natural gas to commercial markets; 
+• 
+changes in customer demand and producers’ supply; 
+• 
+the uncertainty of our ability to attract capital; 
+• 
+compliance with, or the effect of changes in, the extensive governmental
+regulations regarding the oil and natural gas business; 
+• 
+actions of operators of our oil and gas properties; and 
+• 
+weather conditions. 
+10
+Table of Contents 
+The information contained in this report, including the information set forth under the heading
+“Risk Factors,” identifies additional factors that could affect our operating results and
+performance. We urge you to carefully consider these factors and the other cautionary statements in
+this report. Our forward-looking statements speak only as of the date made, and we have no
+obligation to update these forward-looking statements.
+Corporate Offices 
+Our headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned
+space. We also maintain a business office in Houston, Texas, and own or lease field offices in the
+area of the major fields in which we operate properties or have a significant interest. Replacement
+of any of our leased offices would not result in material expenditures by us as alternative
+locations to our leased space are anticipated to be readily available . 
+Employees 
+We had 87 employees as of December 31, 2004, none of whom are currently represented by a union. We
+believe that we have good relations with our employees. We employ six petroleum engineers and
+seven petroleum geoscientists.
+Federal Regulations 
+Sales of Natural Gas. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act
+deregulated prices for all “first sales” of natural gas. Thus, all sales of gas by us may be made
+at market prices, subject to applicable contract provisions.
+Transportation of Natural Gas. The rates, terms and conditions applicable to the interstate
+transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory
+Commission (“FERC”) under the Natural Gas Act (“NGA”), as well as under section 311 of the Natural
+Gas Policy Act (“NGPA”). Since 1985, primarily pursuant to Order Nos. 436 and 636, the FERC has
+implemented regulations intended to make natural gas transportation more accessible to gas buyers
+and sellers on an open-access, non-discriminatory basis.
+In February, 2000, the FERC issued Order No. 637, a rule designed to continue the restructuring of
+the gas industry. Order No. 637 revised the FERC’s policies governing interstate pipeline
+transportation rates and penalties and refined the regulatory framework governing transportation
+terms and conditions to improve open access transportation. The rule has been implemented on a
+pipeline-by-pipeline basis in individual compliance proceedings, almost all of which have been
+settled or have otherwise been terminated.
+In Order No. 2004, issued on November 25, 2003, the FERC issued standards of conduct covering
+regulated interstate pipelines and public utilities (“Transmission Providers”) to govern the
+relationships between regulated Transmission Providers and all of their energy affiliates. Among
+other things, these measures are intended to increase confidence and transparency in the gas market in the wake of recent events
+involving anticompetitive behavior and market abuse.
+On February 12, 2004, the FERC issued a notice of proposed rulemaking in Docket No. RM04-4 designed
+to standardize the procedures for determining the creditworthiness and collateral required of
+shippers on interstate pipelines and to adopt certain standards published by the North American
+Energy Standards Board
+11
+Table of Contents 
+with respect to shipper creditworthiness. The standards are intended to
+facilitate and increase transparency in the creditworthiness evaluation process.
+The FERC is presently reviewing in Docket No. PL04-3, a general policy inquiry, and in individual
+interstate gas pipeline proceedings, whether it should adopt quality and “interchangeability”
+standards for natural gas delivered through interstate pipelines. In general, the issue in these
+proceedings is whether the FERC should impose quality standards for individual pipelines or on a
+broader basis or otherwise regulate the composition and quality of natural gas transported through
+the interstate pipeline system. At the present time the approach that the FERC will take in these
+proceedings and the potential impact on gas supply and on the Company are not clear. In addition,
+on November 22, 2004, the FERC initiated an inquiry on selective discounting for shippers by
+interstate natural gas pipelines. The FERC is focusing the inquiry on whether such discounting
+should continue to be supported by the prices paid by other customers as is the case under current
+FERC policy. One key issue in this inquiry is whether the existing FERC policy should be continued
+for shippers who have access to more than one interstate gas pipeline. Because the inquiry has not
+been completed, its effect on the availability of discounted interstate pipeline transportation
+rates for shippers of natural gas is unclear.
+On October 10, 2003, the U.S. Court of Appeals for the District of Columbia Circuit affirmed a
+district court ruling that severely circumscribed the FERC’s authority under the Outer Continental
+Shelf Lands Act (“OCSLA”). The court found that OCSLA confers upon the Secretary of Interior, not
+the FERC, authority to enforce open access conditions under OCSLA. The FERC retains authority
+under the Natural Gas Act (“NGA”) to enforce open access transportation conditions over natural gas
+pipeline facilities on the Outer Continental Shelf (“OCS”), and under limited conditions over
+natural gas gathering facilities owned directly or indirectly by natural gas pipeline companies.
+The FERC has no authority under the NGA to enforce open access conditions on gathering facilities
+owned by companies that are not affiliated with natural gas pipeline companies. The FERC has no
+authority under the Interstate Commerce Act (“ICA”) to regulate oil pipelines that lie wholly on
+the OCS. In response to the court’s opinion, on April 12, 2004 the Minerals Management Service
+(“MMS”) of the Department of Interior (“DOI”) issued an Advanced Notice of Proposed Rulemaking
+(ANOPR”) requesting comments to assist it in potentially amending its regulations regarding how the
+DOI should ensure that pipelines transporting oil or gas under permits, licenses, easements or
+rights-of-way across the OCS provide open and non-discriminatory access to both owner and non-owner
+shippers under OCSLA. Various parties filed comments in response to the ANOPR. The MMS has not
+yet issued a follow-up Notice of Proposed Rulemaking. It is not clear what regulatory regime the
+MMS will impose to enforce open access transportation on the OCS under OCSLA, nor what impact any
+particular regulatory regime may have upon the ability of the Company to obtain transportation of
+its natural gas and oil production to markets.
+Sales and Transportation of Crude Oil. Sales of crude oil and condensate can be made by us at
+market prices not subject at this time to price controls. The price that we receive from the sale
+of these products will be affected by the cost of transporting the products to market. The rates,
+terms, and conditions applicable to the interstate transportation of oil and related products by
+interstate pipelines are regulated by the FERC under the ICA. Pursuant to the Energy Policy Act of
+1992, which “grandfathered” certain existing rates, the FERC presently regulates interstate oil
+pipeline rates under a light-handed, streamlined regulatory regime where interstate pipeline rates
+can be adjusted annually using an index ceiling based upon the producer price
+index. The FERC recently modified the formula for calculating the index such that the index
+ceilings are now set slightly higher than under the original formula. The FERC will also, under
+defined circumstances, permit alternative ratemaking methodologies for interstate oil pipelines
+such as the use of cost of service rates, settlement rates, and market-based rates. Market-based
+rates will be permitted to the extent the pipeline can demonstrate that it lacks significant market
+power in the market in which it proposes to charge
+12
+Table of Contents 
+market-based rates. The cumulative effect that
+these rules have had on moving our production to market has not been material.
+As stated above, as a result of a recent decision by the U.S. Court of Appeals for the District of
+Columbia Circuit with respect to the transportation of oil and condensate on or across the OCS, the
+DOI, not the FERC, has the authority under OCSLA to enforce open access conditions on oil pipelines
+lying wholly on the OCS.
+Legislative Proposals. In the past, Congress has been active in the area of natural gas
+regulation. There are legislative proposals pending in Congress and in various state legislatures
+which, if enacted, could significantly affect the petroleum industry. At the present time it is
+difficult to predict what proposals, if any, might actually be enacted by Congress or the various
+state legislatures and what effect, if any, such proposals might have on our operations.
+Federal, State or Indian Leases. In the event we conduct operations on federal, state or Indian
+oil and gas leases, such operations must comply with numerous regulatory restrictions, including
+various nondiscrimination statutes, royalty and related valuation requirements, and certain of such
+operations must be conducted pursuant to on-site security regulations and other appropriate permits
+issued by the Bureau of Land Management (“BLM”) or Minerals Management Service (“MMS”) or other
+appropriate federal or state agencies.
+The Company’s OCS leases in federal waters are administered by the MMS and require compliance with
+detailed MMS regulations and orders. The MMS has promulgated regulations implementing restrictions
+on various production-related activities, including restricting the flaring or venting of natural
+gas. Under certain circumstances, the MMS may require our operations on federal leases to be
+suspended or terminated. Any such suspension or termination could materially and adversely affect
+our financial condition and operations. On March 15, 2000, the MMS issued a final rule effective
+June 1, 2000 which amends its regulations governing the calculation of royalties and the valuation
+of crude oil produced from federal leases. Among other matters, this rule amends the valuation
+procedure for the sale of federal royalty oil by eliminating posted prices as a measure of value
+and relying instead on arm’s length sales prices and spot market prices as market value indicators.
+Because we sell our production in the spot market and therefore pay royalties on production from
+federal leases, it is not anticipated that this final rule will have any substantial impact on us.
+The Mineral Leasing Act of 1920 (“Mineral Act”) prohibits direct or indirect ownership of any
+interest in federal onshore oil and gas leases by a foreign citizen of a country that denies
+“similar or like privileges” to citizens of the United States. Such restrictions on citizens of a
+“non-reciprocal” country include ownership or holding or controlling stock in a corporation that
+holds a federal onshore oil and gas lease. If this restriction is violated, the corporation’s
+lease can be canceled in a proceeding instituted by the United States Attorney General. Although
+the regulations of the BLM (which administers the Mineral Act) provide for agency designations of
+non-reciprocal countries, there are presently no such designations in effect. We own interests in
+numerous federal onshore oil and gas leases. It is possible that some of our stockholders may be
+citizens of foreign countries, which at some time in the future might be determined to be
+non-reciprocal under the Mineral Act.
+State Regulations 
+Most states regulate the production and sale of oil and natural gas, including requirements for
+obtaining drilling permits, the method of developing new fields, the spacing and operation of wells
+and the prevention of waste of oil and gas resources. The rate of production may be regulated and
+the maximum daily
+13
+Table of Contents 
+production allowable from both oil and gas wells may be established on a market
+demand or conservation basis or both.
+We may enter into agreements relating to the construction or operation of a pipeline system for the
+transportation of natural gas. To the extent that such gas is produced, transported and consumed
+wholly within one state, such operations may, in certain instances, be subject to the jurisdiction
+of such state’s administrative authority charged with the responsibility of regulating intrastate
+pipelines. In such event, the rates which we could charge for gas, the transportation of gas, and
+the costs of construction and operation of such pipeline would be impacted by the rules and
+regulations governing such matters, if any, of such administrative authority. Further, such a
+pipeline system would be subject to various state and/or federal pipeline safety regulations and
+requirements, including those of, among others, the Department of Transportation. Such regulations
+can increase the cost of planning, designing, installing and operating such facilities. The impact
+of such pipeline safety regulations would not be any more adverse to us than it would be to other
+similar owners or operators of such pipeline facilities.
+Environmental Regulations 
+General. Our activities are subject to federal, state and local laws and regulations governing
+environmental quality and pollution control. Although no assurances can be made, we believe that,
+absent the occurrence of an extraordinary event, compliance with existing federal, state and local
+laws, rules and regulations regulating the release of materials into the environment or otherwise
+relating to the protection of the environment will not have a material effect upon our capital
+expenditures, earnings or competitive position with respect to our existing assets and operations.
+We cannot predict what effect future regulation or legislation, enforcement policies, and claims
+for damages to property, employees, other persons and the environment resulting from our operations
+could have on our activities.
+Our activities with respect to natural gas facilities, including the operation and construction of
+pipelines, plants and other facilities for transporting, processing, treating or storing natural
+gas and other products, are subject to stringent environmental regulation by state and federal
+authorities including the United States Environmental Protection Agency (“EPA”). Such regulation
+can increase the cost of planning, designing, installing and operating such facilities. In most
+instances, the regulatory requirements relate to water and air pollution control measures.
+Although we believe that compliance with environmental regulations will not have a material adverse
+effect on us, risks of substantial costs and liabilities are inherent in oil and gas production
+operations, and there can be no assurance that significant costs and liabilities will not be
+incurred. Moreover, it is possible that other developments, such as stricter environmental laws and
+regulations, and claims for damages to property or persons resulting from oil and gas production,
+would result in substantial costs and liabilities to us.
+Solid and Hazardous Waste. We currently own or lease, and in the past owned or leased, properties
+that have been used for the exploration and production of oil and gas for many years. Although we
+have utilized operating and disposal practices that were standard in the industry at the time,
+hydrocarbons or other solid wastes may have been disposed or released on or under the properties
+owned or leased by us or on or under locations where such wastes have been taken for disposal. In
+addition, many of these properties have been operated by third parties. We have no control over
+such entities’ treatment of hydrocarbons or other solid wastes and the manner in which such
+substances may have been disposed or released. State and federal laws applicable to oil and gas
+wastes and properties have gradually become stricter over time. Under new laws,
+we could be required to remediate property, including groundwater, containing or impacted by
+previously disposed wastes (including wastes disposed or released by prior owners or operators, or
+property
+14
+Table of Contents 
+contamination, including groundwater contamination by prior owners or operators) or to
+perform remedial plugging operations to prevent future or mitigate existing contamination.
+We generate wastes, including hazardous wastes that are subject to the federal Resource
+Conservation and Recovery Act (“RCRA”) and comparable state statutes. The EPA and various state
+agencies have limited the disposal options for certain wastes, including wastes designated as
+hazardous under the RCRA and similar state statutes (“Hazardous Wastes”). Furthermore, it is
+possible that certain wastes generated by our oil and gas operations that are currently exempt from
+treatment as Hazardous Wastes may in the future be designated as Hazardous Wastes under RCRA or
+other applicable statutes and, therefore, may be subject to more rigorous and costly disposal
+requirements.
+Superfund. The federal Comprehensive Environmental Response, Compensation and Liability Act
+(“CERCLA”), also known as the “Superfund” law, generally imposes joint and several liability for
+costs of investigation and remediation and for natural resource damages, without regard to fault or
+the legality of the original conduct, on certain classes of persons with respect to the release
+into the environment of substances designated under CERCLA as hazardous substances (“Hazardous
+Substances”). These classes of persons, or so-called potentially responsible parties (“PRPs”),
+include the current and certain past owners and operators of a facility where there has been a
+release or threat of release of a Hazardous Substance and persons who disposed of or arranged for
+the disposal of Hazardous Substances found at a site. CERCLA also authorizes the EPA and, in some
+cases, third parties to take actions in response to threats to the public health or the environment
+and to seek to recover from the PRPs the costs of such action. Although CERCLA generally exempts
+“petroleum” from the definition of Hazardous Substance, in the course of its operations, we have
+generated and will generate wastes that may fall within CERCLA’s definition of Hazardous Substance.
+We may also be the owner or operator of sites on which Hazardous Substances have been released.
+To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under
+CERCLA. We also do not know of any prior owners or operators of our properties that are named as
+PRPs related to their ownership or operation of such properties. Certain states, including
+Louisiana, have comparable statutes. In the event contamination is discovered at a site on which
+we are or have been an owner or operator, we could be liable for costs of investigation and
+remediation and natural resource damages.
+Clean Water Act . The Clean Water Act (“CWA”) imposes restrictions and strict controls regarding
+the discharge of wastes including produced waters and other oil and natural gas wastes, into waters
+of the United States, a term broadly defined. These controls have become more stringent over the
+years, and it is probable that additional restrictions will be imposed in the future. Permits must
+be obtained to discharge pollutants into federal waters. The CWA provides for civil, criminal and
+administrative penalties for unauthorized discharges of oil and hazardous substances and of other
+pollutants. It imposes substantial potential liability for the costs of removal or remediation
+associated with discharges of oil or hazardous substances and other pollutants. State laws
+governing discharges to water also provide varying civil, criminal and administrative penalties and
+impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous
+substances, into state waters. In addition, the EPA has promulgated regulations that may require
+us to obtain permits to discharge storm water runoff, including discharges associated with
+construction activities. In the event of an unauthorized discharge of wastes, we may be liable for
+penalties and costs.
+Oil Pollution Act. The Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill
+provisions of the CWA, imposes certain duties and liabilities on certain “responsible parties”
+related to the prevention of oil spills and damages resulting from such spills in or threatening
+United States waters or adjoining shorelines. A liable “responsible party” includes the owner or
+operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the
+substantial threat of discharge, or in the case of offshore
+facilities, the lessee or permittee of the area in which a discharging facility is located. The
+OPA assigns joint
+15
+Table of Contents 
+and several liability, without regard to fault, to each liable party for oil
+removal costs and a variety of public and private damages. Although defenses and limitations exist
+to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial
+threat of discharge, we may be liable for costs and damages.
+The OPA also imposes ongoing requirements on a responsible party, including proof of financial
+responsibility to cover at least some costs in a potential spill. Certain amendments to the OPA
+that were enacted in 1996 require owners and operators of offshore facilities that have a worst
+case oil spill potential of more than 1,000 barrels to demonstrate financial responsibility in
+amounts ranging from $10 million in specified state waters and $35 million in federal OCS waters,
+with higher amounts, up to $150 million based upon worst case oil-spill discharge volume
+calculations. We believe that we have established adequate proof of financial responsibility for
+our offshore facilities.
+Air Emissions. Our operations are subject to local, state and federal regulations for the control
+of emissions from sources of air pollution. Federal and state laws require new and modified
+sources of air pollutants to obtain permits prior to commencing construction. Major sources of air
+pollutants are subject to more stringent, federally imposed requirements including additional
+permits. Federal and state laws designed to control hazardous (toxic) air pollutants, might
+require installation of additional controls. Administrative enforcement actions for failure to
+comply strictly with air pollution regulations or permits are generally resolved by payment of
+monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies
+could bring lawsuits for civil penalties or require us to forego construction, modification or
+operation of certain air emission sources.
+Coastal Coordination. There are various federal and state programs that regulate the conservation
+and development of coastal resources. The federal Coastal Zone Management Act (“CZMA”) was passed
+in 1972 to preserve and, where possible, restore the natural resources of the Nation’s coastal
+zone. The CZMA provides for federal grants for state management programs that regulate land use,
+water use and coastal development.
+Various states, such as Alabama, Louisiana and Texas, also have coastal management programs, which
+provide for, among other things, the coordination among local and state authorities to protect
+coastal resources through regulating land use, water, and coastal development. Coastal management
+programs also may provide for the review of state and federal agency rules and agency actions for
+consistency with the goals and policies of the state coastal management plan. This review may
+impact agency permitting and review activities and add an additional layer of review to certain
+activities undertaken by us.
+OSHA and other Regulations. We are subject to the requirements of the federal Occupational Safety
+and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the
+EPA community right-to-know regulations under Title III of CERCLA and similar state statutes
+require us to organize and/or disclose information about hazardous materials used, stored or
+produced in our operations.
+Our management believes that we are in substantial compliance with current applicable environmental
+laws and regulations and that continued compliance with existing requirements would not have a
+material adverse impact on us.
+Commitments and Contingencies 
+The Company’s activities are subject to federal, state and local laws and regulations governing
+environmental quality and pollution control. Although no assurances can be made, the Company
+believes
+16
+Table of Contents 
+that, absent the occurrence of an extraordinary event, compliance with existing federal, state and
+local laws, rules and regulating the release of materials in the environment or otherwise relating
+to the protection of the environment will not have a material effect upon the capital expenditures,
+earnings or the competitive position of the Company with respect to its existing assets and
+operations. The Company cannot predict what effect additional regulation or legislation,
+enforcement polices thereunder, and claims for damages to property, employees, other person, and
+the environment resulting from the Company’s operations could have on its activities.
+Property Summary 
+We are engaged in the exploration, development, acquisition and production of oil and gas
+properties and provide oil and gas property management services for other investors. Our
+properties are concentrated offshore in the Gulf of Mexico and onshore, primarily, in Louisiana and
+Alabama. We have historically increased our reserves and production by focusing primarily on low to
+moderate risk exploration and acquisition opportunities in the Gulf of Mexico shelf area. In 1998,
+we expanded our area of exploration to include the Gulf of Mexico deepwater area. As of December
+31, 2004, our estimated net proved reserves totaled 19.7 million barrels of oil (“MMBbl”) and 72.6
+billion cubic feet of natural gas (“Bcf”), with a pre-tax present value, discounted at 10%, of the
+estimated future net revenues based on constant prices in effect at year-end (“Discounted Cash
+Flow”) of $612.6 million. Oil constitutes approximately 62% on an equivalent basis of our total
+estimated proved reserves and approximately 50% of our total estimated proved reserves are proved
+developed reserves.
+Our Medusa (Mississippi Canyon Blocks 538/582) and Habanero (Garden Banks Block 341) discoveries
+began production in the fourth quarter of 2003. A detailed discussion of each of these properties
+is provided in the “Significant Properties” section of this report. These two deepwater
+discoveries were primarily responsible for an increase in our 2004 production by approximately 57%
+from 2003 levels.
+17
+Table of Contents 
+Significant Properties 
+The following table shows discounted cash flows and estimated net proved oil and gas reserves by
+major field, within the focus area, for our eight largest fields and for all other properties
+combined at December 31, 2004.
+Pre-tax 
+Estimated Net Proved Reserves 
+Discounted 
+Present 
+Oil 
+Gas 
+Total 
+Value 
+Operator 
+(MBbls) 
+(MMcf) 
+(MMcfe) 
+($000) 
+(a)(b) 
+Gulf of Mexico Deepwater: 
+Mississippi Canyon Blocks 538/582
+“Medusa” 
+Murphy 
+6,945 
+4,970 
+46,640 
+$ 
+155,829 
+Garden Banks Block 341
+“Habanero” 
+Shell 
+4,070 
+10,390 
+34,812 
+139,153 
+Garden Banks Blocks
+738/782/826/827
+“Entrada” 
+BP 
+7,772 
+29,126 
+75,760 
+219,368 
+Gulf of Mexico Shelf: 
+Mobile Blocks 863/864/907/908 
+Callon 
+— 
+4,068 
+4,068 
+9,929 
+Mobile Blocks 952/953/955 
+Callon 
+— 
+9,362 
+9,362 
+29,199 
+North Padre Island Block 913 
+Callon 
+2 
+3,457 
+3,467 
+11,133 
+High Island Block 119 
+Kerr-McGee 
+32 
+2,999 
+3,192 
+18,560 
+Onshore and Other: 
+Big Escambia Creek 
+Vintage 
+387 
+1,627 
+3,949 
+8,970 
+Other 
+Various 
+540 
+6,620 
+9,858 
+20,454 
+Total Net Proved Reserves 
+19,748 
+72,619 
+191,108 
+$ 
+612,595 
+(a) 
+Represents the present value of future net cash flows before deduction of federal income
+taxes, discounted at 10%, attributable to estimated net proved reserves as of December 31,
+2004, as set forth in the Company’s reserve reports prepared by its independent petroleum
+reserve engineers, Huddleston & Co., Inc. of Houston, Texas. 
+(b) 
+Includes a reduction for estimated plugging and abandonment costs that is reflected as a
+liability on our balance sheet at December 31, 2004, in accordance with Statement of Financial
+Accounting Standards No. 143. See the Oil and Gas Reserve table for the standardized measure
+of discounted future net cash flow which is a required calculation by the SEC. 
+18
+Table of Contents 
+Gulf of Mexico Deepwater 
+Medusa, Mississippi Canyon Blocks 538/582 
+Our Medusa deepwater discovery was announced in September 1999, after we drilled the initial test
+well in 2,235 feet of water to a total depth of 16,241 feet and encountered over 120 feet of pay in
+two intervals. Subsequent sidetrack drilling from the wellbore was used to determine the extent of
+the discovery and a second well was drilled in the first quarter of 2000 to further delineate the
+extent of the pay intervals. We own a 15% working interest, Murphy Exploration & Production
+Company, the operator, owns a 60% working interest and ENI Deepwater, LLC, owns the remaining 25%
+working interest.
+In 2001 a drilling program began which included four development wells and one sidetrack. The
+program included production casing being set on six wells to provide initial production take-points
+and was completed in the first half of 2002. The construction of a floating production system,
+spar, at Medusa was completed during the second quarter of 2003. The A-1 well was completed and
+tied into the spar and commenced production in late November 2003. The remaining five wells were
+completed and commenced production in 2004. During 2004 the field produced an average of 20.5
+million cubic feet of natural gas equivalent (“MMcfe”) per day net to us. The field is currently
+producing approximately 40,000 barrels of crude oil and 40 million cubic feet of natural gas
+(“MMcf”) per day, or 36.1 MMcfe per day net to our interest.
+In December 2003, we transferred our undivided 15% working interest in the spar production
+facilities to Medusa Spar LLC in exchange for cash proceeds of approximately $25 million and a 10%
+ownership interest in the LLC. A detailed discussion of this transaction is included in
+Management’s Discussion and Analysis of Financial Condition and Results of Operations-“Off-Balance
+Sheet Arrangements”.
+Habanero, Garden Banks Block 341 
+During February 1999, the initial test well on our Habanero deepwater discovery encountered over
+200 feet of net pay in two zones. Located in 2,000 feet of water, the well was drilled to a
+measured depth of 21,158 feet. We own an 11.25% working interest in the well. The well is operated
+by Shell Deepwater Development Inc., which owns a 55% working interest, with the remaining working
+interest being owned by Murphy.
+A field delineation program began in mid-year 2001, which included three sidetracks of the
+discovery well. Production casing was set on this well through one of the sidetracks to the
+Habanero 52 oil and gas sand and the Habanero 55 gas sand. Also, a development well was drilled in
+the summer of 2003 which provides a take-point for production from the Habanero 52 oil sand. By
+means of a sub-sea completion and tie back to an existing production facility in the area operated
+by Shell, production from the Habanero 52 oil sand commenced in late November 2003 and from the
+Habanero 55 gas sand in January 2004. In July the #2 well producing the Habanero 52 oil sand
+developed mechanical difficulties with a subsurface control value and was shut-in resulting in a
+significant loss of production. Repairs were completed and production was restored in late
+December. In addition, the #1 well producing the Habanero 55 gas sand was recompleted to the
+Habanero 55 oil sand in December. Our net production during 2004 from the Habanero field was
+approximately 11.1 MMcfe per day. The field is currently producing approximately 21,000 barrels of
+crude oil and 35 MMcf per day, or 15.5 MMcfe per day net to our interest.
+19
+Table of Contents 
+Entrada, Garden Banks Blocks 738/782/826/827 
+The Entrada discovery is located in approximately 4,500 feet of water in the Gulf of Mexico. Two
+wells and seven sidetracks have been drilled to date. The Entrada Area is characterized by a
+northwest plunging salt ridge with multiple stacked amplitudes trapped against the salt and various
+faults. We own a 20% working interest in this discovery with BP, the operator, holding the
+remaining working interest.
+An integrated project team has been formed by the working interest owners and is reviewing various
+plans for development of the field. One scenario is to negotiate a tie-in of Entrada into existing
+production facilities. The owners of an adjacent discovery have commenced production from
+facilities that will enable them to be a regional off-take point in Southeastern Garden Banks.
+These plans include handling third party tie-ins. Production from Entrada under this scenario
+could possibly commence in 2007.
+Gulf of Mexico Shelf 
+Mobile Blocks 863/864/ 907 
+We own an average 64.6% working interest in these blocks and we are the operator. The Mobile 864
+unit, in which we have a 66.4% working interest, has four producing wells, unit production
+facilities and covers portions of these three blocks. During 2004 the unit produced an average of
+2.9 MMcf per day net to us.
+Mobile Blocks 952/953/955 
+We own a 100% working interest in these three blocks and we are the operator. In the fourth
+quarter of 2001, we initiated a production acceleration program for Mobile Blocks 952, 953 and 955,
+which were being produced through the Mobile Block 864 unit facilities and were production
+constrained. An acceleration well was successfully drilled in the fourth quarter of 2001 and
+stand-alone production facilities were installed and production flow lines were rerouted to the new
+facilities. Production commenced through the new facilities in April 2002. In order to completely
+produce the proved reserves of the field we drilled a development well on Mobile Block 955 during
+the first quarter of 2004. Production from the field for 2004 was 14.7 MMcf per day net to us.
+High Island Block 119 
+An initial exploratory well and one development well were drilled and completed in 2004. First
+production began in the third quarter of 2004. An exploratory well in an offsetting fault block
+was spud late in the fourth quarter of 2004 and was completed in 2005. We own a 22% working
+interest and Westport Resources is the operator. Production for the fourth quarter of 2004 net to
+us was 3.7 MMcfe per day. Peak production should be reached by the end of the first quarter of
+2005 at a rate estimated to be 50 MMcfe per day, or 8.5 MMcfe per day net to our interest.
+North Padre Island Block 913 
+An exploratory well was drilled to a vertical depth of 8,082 feet in the fourth quarter of 2004 and
+found apparent natural gas pay in multiple intervals. Currently, the well is being completed and
+will be tied back to existing infrastructure on a nearby block. We are the operator and own a 50%
+working interest. First production is forecast to be in the third quarter of 2005.
+20
+Table of Contents 
+Onshore and Other 
+Big Escambia Creek 
+This gas field in south Alabama produces from the Smackover formation at depths ranging from 15,100
+to 15,600 feet and is operated by Vintage. We own an average working interest of 4.9% (5.5% net
+revenue interest), in six wells and a 2.2% average royalty interest in another five wells. This
+field produced 0.7 MMcfe per day net to our interest in 2004. The field has an estimated reserve
+life in excess of 10 years given current production rates.
+Other 
+We own various royalty and working interests in numerous onshore areas and the Gulf of Mexico other
+than the fields discussed above.
+Oil and Gas Reserves 
+The following table sets forth certain information about our estimated proved reserves as of the
+dates set forth below.
+Years Ended December 31, 
+2004 
+2003 
+2002 
+(In thousands) 
+Proved developed: 
+Oil (Bbls) 
+10,292 
+9,919 
+1,056 
+Gas (Mcf) 
+33,982 
+31,415 
+37,631 
+Mcfe 
+95,735 
+90,926 
+43,966 
+Proved undeveloped: 
+Oil (Bbls) 
+9,456 
+13,790 
+22,987 
+Gas (Mcf) 
+38,637 
+43,276 
+53,908 
+Mcfe 
+95,373 
+126,017 
+191,833 
+Total proved: 
+Oil (Bbls) 
+19,748 
+23,709 
+24,043 
+Gas (Mcf) 
+72,619 
+74,691 
+91,539 
+Mcfe 
+191,108 
+216,943 
+235,799 
+Estimated
+pre-tax future net cash flows (a) 
+$ 
+892,145 
+$ 
+838,847 
+$ 
+970,199 
+Pre-tax discounted present value (a) 
+$ 
+612,595 
+$ 
+570,463 
+$ 
+623,946 
+Standardized measure of discounted future
+net cash flows(a) 
+$ 
+515,893 
+$ 
+519,026 
+$ 
+556,046 
+(a) 
+Includes a reduction for estimated plugging and abandonment costs that is reflected as
+a liability on our balance sheet at December 31, 2004, in accordance with Statement of
+Financial Accounting Standards No. 143. 
+21
+Table of Contents 
+Our independent reserve engineers, Huddleston & Co., Inc., prepared the estimates of the proved
+reserves and the future net cash flows and present value thereof attributable to such proved
+reserves. Reserves were estimated using oil and gas prices and production and development costs in
+effect on December 31 of each such year, without escalation, and were otherwise prepared in
+accordance with Securities and Exchange Commission regulations regarding disclosure of oil and gas
+reserve information.
+There are numerous uncertainties inherent in estimating quantities of proved reserves, including
+many factors beyond our control or the control of the reserve engineers. Reserve engineering is a
+subjective process of estimating underground accumulations of oil and gas that cannot be measured
+in an exact manner. The accuracy of any reserve or cash flow estimate is a function of the quality
+of available data and of engineering and geological interpretation and judgment. Estimates by
+different engineers often vary, sometimes significantly. In addition, physical factors, such as
+the results of drilling, testing and production subsequent to the date of an estimate, as well as
+economic factors, such as an increase or decrease in product prices that renders production of such
+reserves more or less economic, may justify revision of such estimates. Accordingly, reserve
+estimates could be different from the quantities of oil and gas that are ultimately recovered.
+We have not filed any reports with other federal agencies which contain an estimate of total proved
+net oil and gas reserves during our last fiscal year.
+Present Activities and Productive Wells 
+The following table sets forth the wells we have drilled and completed during the periods
+indicated. All such wells were drilled in the continental United States primarily in federal and
+state waters in the Gulf of Mexico.
+Years Ended December 31, 
+2004 
+2003 
+2002 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development: 
+Oil 
+— 
+— 
+2 
+.23 
+2 
+.30 
+Gas 
+2 
+1.22 
+— 
+— 
+— 
+— 
+Non-productive 
+— 
+— 
+— 
+— 
+1 
+.40 
+Total 
+2 
+1.22 
+2 
+.23 
+3 
+.70 
+Exploration: 
+Oil 
+— 
+— 
+1 
+.15 
+— 
+— 
+Gas 
+2 
+.72 
+— 
+— 
+1 
+.22 
+Non-productive 
+5 
+1.24 
+1 
+.20 
+1 
+.50 
+Total 
+7 
+1.96 
+2 
+.35 
+2 
+.72 
+22
+Table of Contents 
+The following table sets forth our productive wells as of December 31, 2004:
+Wells 
+Gross 
+Net 
+Oil: 
+Working interest 
+46.00 
+4.06 
+Royalty interest 
+189.00 
+3.15 
+Total 
+235.00 
+7.21 
+Gas: 
+Working interest 
+39.00 
+17.34 
+Royalty interest 
+214.00 
+1.69 
+Total 
+253.00 
+19.03 
+A well is categorized as an oil well or a natural gas well based upon the ratio of oil to gas
+reserves on a Mcfe basis. However, some of our wells produce both oil and gas. At December 31,
+2004, we had no wells with multiple completions. At December 31, 2004, we had 1 gross (0.15 net)
+development oil well and 1 gross (0.22 net) exploration gas well in progress.
+Leasehold Acreage 
+The following table shows our approximate developed and undeveloped (gross and net) leasehold
+acreage as of December 31, 2004.
+Leasehold Acreage 
+Developed 
+Undeveloped 
+Location 
+Gross 
+Net 
+Gross 
+Net 
+Louisiana 
+6,060 
+3,952 
+5,386 
+3,173 
+Other states 
+— 
+— 
+681 
+509 
+Federal waters 
+96,743 
+66,400 
+266,380 
+70,802 
+Total 
+102,803 
+70,352 
+272,447 
+74,484 
+As of December 31, 2004, we owned various royalty and overriding royalty interests in 1,336 net
+developed and 6,862 net undeveloped acres. In addition, we owned 4,157 developed and 121,843
+undeveloped mineral acres.
+23
+Table of Contents 
+Major Customers 
+Our production is sold generally on month-to-month contracts at prevailing prices. The following
+table identifies customers to whom we sold a significant percentage of our total oil and gas
+production during each of the 12-month periods ended:
+December 31, 
+2004 
+2003 
+2002 
+Petrocom Energy Group, Ltd. 
+— 
+4 
+% 
+4 
+% 
+Dynegy 
+— 
+5 
+% 
+7 
+% 
+Prior Energy Corporation 
+— 
+20 
+% 
+— 
+Reliant Energy Services 
+6 
+% 
+28 
+% 
+70 
+% 
+Louis Dreyfus Energy Services 
+23 
+% 
+27 
+% 
+— 
+Shell Trading Company 
+30 
+% 
+— 
+— 
+Plains Marketing, L.P. 
+13 
+% 
+— 
+— 
+Conoco Phillips Company 
+8 
+% 
+— 
+— 
+Chevron Texaco Natural Gas 
+6 
+% 
+— 
+— 
+Because alternative purchasers of oil and gas are readily available, we believe that the loss of
+any of these purchasers would not result in a material adverse effect on our ability to market
+future oil and gas production.
+Title to Properties 
+We believe that the title to our oil and gas properties is good and defensible in accordance with
+standards generally accepted in the oil and gas industry, subject to such exceptions which, in our
+opinion, are not so material as to detract substantially from the use or value of such properties.
+Our properties are typically subject, in one degree or another, to one or more of the following:
+• 
+royalties and other burdens and obligations, express or implied, under oil and gas leases; 
+• 
+overriding royalties and other burdens created by us or our predecessors in title; 
+• 
+a variety of contractual obligations (including, in some cases, development obligations)
+arising under operating agreements, farmout agreements, production sales contracts and
+other agreements that may affect the properties or their titles; 
+• 
+back-ins and reversionary interests existing under purchase agreements and leasehold
+assignments; 
+• 
+liens that arise in the normal course of operations, such as those for unpaid taxes,
+statutory liens securing obligations to unpaid suppliers and contractors and contractual
+liens under operating agreements; 
+• 
+pooling, unitization and communitization agreements, declarations and orders; and 
+• 
+easements, restrictions, rights-of-way and other matters that commonly affect property. 
+To the extent that such burdens and obligations affect our rights to production revenues, they have
+been taken into account in calculating our net revenue interests and in estimating the size and
+value of our reserves. We believe that the burdens and obligations affecting our properties are
+conventional in the industry for properties of the kind owned by us.
+24
+Table of Contents 
+ITEM 3. LEGAL PROCEEDINGS 
+We are a defendant in various legal proceedings and claims, which arise in the ordinary course of
+our business. We do not believe the ultimate resolution of any such actions will have a material
+affect on our financial position or results of operations.
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 
+There were no matters submitted to a vote of security holders during the fourth quarter of 2004.
+25
+Table of Contents 
+PART II. 
+ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS 
+Our common stock trades on the New York Stock Exchange under the symbol “CPE”. The following table
+sets forth the high and low sale prices per share as reported for the periods indicated.
+Quarter Ended 
+High 
+Low 
+2003: 
+First quarter 
+$ 
+4.35 
+$ 
+3.35 
+Second quarter 
+8.44 
+3.66 
+Third quarter 
+7.95 
+5.46 
+Fourth quarter 
+11.48 
+7.31 
+2004: 
+First quarter 
+$ 
+11.23 
+$ 
+8.70 
+Second quarter 
+14.27 
+10.15 
+Third quarter 
+14.40 
+11.10 
+Fourth quarter 
+14.72 
+12.30 
+As of March 3, 2005, there were approximately 4,337 common stockholders of record.
+We have never paid dividends on our common stock and intend to retain our cash flow from
+operations, net of preferred stock dividends, for the future operation and development of our
+business. In addition, our primary credit facility and the terms of our outstanding subordinated
+debt prohibit the payment of cash dividends on our common stock.
+ITEM 6. SELECTED FINANCIAL DATA 
+The following table sets forth, as of the dates and for the periods indicated, selected financial
+information about us. The financial information for each of the five years in the period ended
+December 31, 2004 has been derived from our audited Consolidated Financial Statements for such
+periods. The information should be read in conjunction with “Management’s Discussion and Analysis
+of Financial Condition and Results of Operations” and the Consolidated Financial Statements and
+Notes thereto. The following information is not necessarily indicative of our future results.
+26
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+SELECTED HISTORICAL FINANCIAL INFORMATION 
+(In thousands, except per share amounts) 
+Years Ended December 31, 
+2004 
+2003 
+2002 
+2001 
+2000 
+Statement of Operations Data: 
+Operating revenues: 
+Oil and gas sales 
+$ 
+119,802 
+$ 
+73,697 
+$ 
+61,171 
+$ 
+60,010 
+$ 
+56,310 
+Operating expenses: 
+Lease operating expenses 
+22,308 
+11,301 
+11,030 
+11,252 
+9,339 
+Depreciation, depletion and amortization 
+47,453 
+28,253 
+27,096 
+21,081 
+17,153 
+General and administrative 
+8,758 
+4,713 
+4,705 
+4,635 
+4,155 
+Accretion expense 
+3,400 
+2,884 
+— 
+— 
+— 
+Derivative expense 
+1,371 
+535 
+708 
+— 
+— 
+Total operating expenses 
+83,290 
+47,686 
+43,539 
+36,968 
+30,647 
+Income (loss) from operations 
+36,512 
+26,011 
+17,632 
+23,042 
+25,663 
+Other (income) expenses: 
+Interest expense 
+20,137 
+30,614 
+26,140 
+12,805 
+8,420 
+Other (income) 
+(357 
+) 
+(444 
+) 
+(1,004 
+) 
+(1,742 
+) 
+(1,767 
+) 
+Loss on early extinguishment of debt 
+3,004 
+5,573 
+— 
+— 
+— 
+Gain on sale of pipeline 
+— 
+— 
+(2,454 
+) 
+— 
+— 
+Gain on sale of Enron derivatives 
+— 
+— 
+(2,479 
+) 
+— 
+— 
+Writedown of Enron derivatives 
+— 
+— 
+— 
+9,186 
+— 
+Total other (income) expenses 
+22,784 
+35,743 
+20,203 
+20,249 
+6,653 
+Income (loss) before income taxes 
+13,728 
+(9,732 
+) 
+(2,571 
+) 
+2,793 
+19,010 
+Income tax expense (benefit) 
+(6,697 
+) 
+8,432 
+(900 
+) 
+977 
+6,463 
+Income (loss) before Medusa Spar LLC and
+cumulative effect of change in accounting principle 
+20,425 
+(18,164 
+) 
+(1,671 
+) 
+1,816 
+12,547 
+Income (loss) on Medusa Spar LLC, net of tax 
+1,076 
+(8 
+) 
+— 
+— 
+— 
+Income (loss) before cumulative effect of change
+in accounting principle 
+21,501 
+(18,172 
+) 
+(1,671 
+) 
+1,816 
+12,547 
+Cumulative effect of change in accounting principle,
+net of tax 
+— 
+181 
+— 
+— 
+— 
+Net income (loss) 
+21,501 
+(17,991 
+) 
+(1,671 
+) 
+1,816 
+12,547 
+Preferred stock dividends 
+1,272 
+1,277 
+1,277 
+1,277 
+2,403 
+Net income (loss) available to common shares 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+$ 
+(2 ,948 
+) 
+$ 
+539 
+$ 
+10,144 
+27
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+SELECTED HISTORICAL FINANCIAL INFORMATION 
+(In thousands, except per share amounts) 
+Years Ended December 31, 
+2004 
+2003 
+2002 
+2001 
+2000 
+Net income (loss) available to common shares 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+$ 
+(2,948 
+) 
+$ 
+539 
+$ 
+10,144 
+Net income (loss) per common share: 
+Basic: 
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+1.28 
+$ 
+(1.42 
+) 
+$ 
+(.22 
+) 
+$ 
+.04 
+$ 
+.82 
+Cumulative effect of change in accounting principle,
+net of tax 
+— 
+.01 
+— 
+— 
+— 
+Net income (loss) available to common 
+$ 
+1.28 
+$ 
+(1.41 
+) 
+$ 
+(.22 
+) 
+$ 
+.04 
+$ 
+.82 
+Diluted: 
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+1.22 
+$ 
+(1.42 
+) 
+$ 
+(.22 
+) 
+$ 
+.04 
+$ 
+.80 
+Cumulative effect of change in accounting principle,
+net of tax 
+— 
+.01 
+— 
+— 
+— 
+Net income (loss) available to common 
+$ 
+1.22 
+$ 
+(1.41 
+) 
+$ 
+(.22 
+) 
+$ 
+.04 
+$ 
+.80 
+Shares used in computing net income (loss) per common share: 
+Basic 
+15,796 
+13,662 
+13,387 
+13,273 
+12,420 
+Diluted 
+17,678 
+13,662 
+13,387 
+13,366 
+12,745 
+Balance Sheet Data (end of period): 
+Oil and gas properties, net 
+$ 
+406,690 
+$ 
+390,163 
+$ 
+377,661 
+$ 
+343,158 
+$ 
+258,613 
+Total assets 
+$ 
+457,523 
+$ 
+496,032 
+$ 
+410,613 
+$ 
+372,095 
+$ 
+301,569 
+Long-term debt, less current portion 
+$ 
+192,351 
+$ 
+214,885 
+$ 
+248,269 
+$ 
+161,733 
+$ 
+134,000 
+Stockholders’ equity 
+$ 
+198,312 
+$ 
+133,261 
+$ 
+140,960 
+$ 
+147,224 
+$ 
+136,328 
+We use the full-cost method of accounting. Under this method of accounting, our net
+capitalized costs to acquire explore and develop oil and gas properties may not exceed the
+standardized measure of our proved reserves. If these capitalized costs exceed a ceiling amount,
+the excess is charged to expense.
+28
+Table of Contents 
+ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+The following discussion is intended to assist in an understanding of our financial condition and
+results of operations. Our Consolidated Financial Statements and Notes thereto contain detailed
+information that should be referred to in conjunction with the following discussion. See Item 8.
+“Financial Statements and Supplementary Data.”
+General 
+We have been engaged in the exploration, development, acquisition and production of oil and gas
+properties since 1950. Our revenues, profitability and future growth and the carrying value of our
+oil and gas properties are substantially dependent on prevailing prices of oil and gas and our
+ability to find, develop and acquire additional oil and gas reserves that are economically
+recoverable. Our ability to maintain or increase our borrowing capacity and to obtain additional
+capital on attractive terms is also influenced by oil and gas prices.
+Significant events of our financial and operating results for the year ended December 31, 2004
+included:
+• 
+an increase in 2004 production and revenues of 57% and 63%, respectively, over 2003
+levels; 
+• 
+borrowing an additional $15 million for a term of seven years at an interest rate of
+9.75% pursuant to a senior unsecured credit agreement; 
+• 
+closing a three-year senior secured credit facility with an initial borrowing base of
+$60 million which can be increased to a maximum of $175 million; 
+• 
+closing the public offering of 3,450,000 shares of common stock priced at $13.25 per
+share raising net proceeds of approximately $44 million, after expenses; 
+• 
+sub-debt redemptions and bank line paydown; and 
+• 
+an income tax benefit of $6.7 million as the result of reversing a valuation allowance
+which was established in 2003 against our deferred tax assets. See Note 3 to the Company’s Consolidated Financial
+Statements for a more detailed discussion. 
+The additional borrowing pursuant to our 9.75% senior unsecured credit agreement and the public
+offering of shares of our common stock allowed us to redeem $33 million of senior subordinated
+notes which were maturing in 2005, redeem $10 million of 12% loans maturing in March 2005 and
+reduce the outstanding balance under our senior secured credit facility. In addition, excess funds
+were used for general corporate purposes. As a result, we expect that planned 2005 capital
+expenditures of approximately $80 million will be funded with cash flows from operations. The
+current borrowing base is $60 million under the senior secured credit facility and $52.7 million
+was available on December 31, 2004. For a more detailed discussion of outstanding debt see Note 5
+to our Consolidated Financial Statements.
+Our estimated net proved oil and gas reserves decreased at December 31, 2004 to 191 Bcfe. This
+represents a decrease of 12% from previous year-end 2003 estimated proved reserves of 217 Bcfe.
+29
+Table of Contents 
+Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in
+the supply of and demand for oil and gas, market uncertainty and a variety of additional factors
+beyond our control. These factors include weather conditions in the United States, the condition
+of the United States economy, the actions of the Organization of Petroleum Exporting Countries,
+governmental regulation, political stability in the Middle East and elsewhere, the foreign supply
+of crude oil and natural gas, the price of foreign imports and the availability of alternate fuel
+sources. Any substantial and extended decline in the price of crude oil or natural gas would have
+an adverse effect on our carrying value of our proved reserves, borrowing capacity, revenues,
+profitability and cash flows from operations. We use derivative financial instruments (see Note 6
+to our Consolidated Financial Statements and Item 7A. “Quantitative and Qualitative Disclosures
+About Market Risks”) for price protection purposes on a limited amount of our future production and
+do not use them for trading purposes. On a Mcfe basis, natural gas represents 43% of the budgeted
+2005 production and 38% of proved reserves at year-end 2004.
+Inflation has not had a material impact on us and is not expected to have a material impact on us
+in the future.
+Summary of Significant Accounting Policies 
+On December 16, 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised
+2004), (“SFAS 123R”) Share-Based Payment, which is a revision of Statement of Financial Accounting
+Standards No. 123, (“SFAS 123”) Accounting for Stock-Based Compensation . SFAS 123R supersedes APB
+Opinion No. 25, Accounting for Stock Issued to Employees , and amends Statement of Financial
+Accounting Standards No. 95, Statement of Cash Flows . Generally, the approach in SFAS 123R is
+similar to the approach described in SFAS 123. However, SFAS 123R requires all share-based
+payments to employees, including grants of employee stock options, to be recognized in the income
+statement based on their fair values. Pro forma disclosure is no longer an alternative.
+SFAS 123R must be adopted no later than July 1, 2005. Early adoption will be permitted in periods
+in which financial statements have not yet been issued.
+SFAS 123R permits public companies to adopt its requirements
+using one of two methods below:
+• 
+A “modified prospective” method in which compensation cost is recognized beginning with the effective date (a) based on the requirements of SFAS 123R
+for all share-based payments granted after the effective date and (b) based on the requirements of SFAS 123 for all awards granted to employees
+prior to the effective date of SFAS 123R that remain unvested on the effective date; or 
+• 
+A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to
+restate based on the amounts previously recognized under SFAS 123 for purposes of pro forma disclosures either (a) all prior periods presented or (b)
+prior interim periods of the year of adoption. 
+We expect to adopt SFAS 123R
+on July 1, 2005 using the modified prospective method.
+As permitted by SFAS 123, we currently accounts for share-based payments to employees
+using Opinion 25’s intrinsic value method and, as such, generally recognizes no compensation cost
+for employee stock options. Accordingly, the adoption of SFAS 123R’s fair value method will have a
+significant impact on our result of operations, although it will have no impact on our overall
+financial position. The impact of adoption of SFAS 123R cannot be predicted at this time because
+it will depend on levels of share-based payments granted in the future. However, had we adopted
+SFAS 123R in prior periods, the impact of that standard would have approximated the impact of SFAS
+123 as described in the disclosure of pro forma net income and earnings per share in Note 2 to our
+consolidated financial statements.
+In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest
+Entities, an Interpretation of Accounting Research Bulletin (ARB) 51” (“FIN 46”). FIN 46 addresses
+consolidation by business enterprises of variable interest entities (“VIEs”). We adopted FIN 46,
+as revised, as of December 31, 2003, which had no impact on our results of operations or financial
+position.
+In September 2004, the SEC issued Staff Accounting Bulletin (“SAB”) No. 106 which expressed the
+Staff’s views regarding the application of Statement of Financial Accounting Standards (“SFAS”) No.
+143 “Accounting for Asset Retirement Obligations” by oil and gas producing companies following
+full-cost accounting method. SAB No. 106 specifies that subsequent to the adoption of SFAS No. 143
+an oil and gas
+30
+Table of Contents 
+company following the full-cost method of accounting should include assets recorded
+in connection with the recognition of an asset retirement obligation pursuant to SFAS No. 143 as
+part of the costs subject to the full -cost ceiling limitation. The future cash outflows
+associated with settling the recorded asset retirement obligations should be excluded from the
+computation of the present value of estimated future net revenues used in applying the ceiling
+test. The Company will be required to adopt the provisions of SAB No. 106 prospectively in the
+first quarter of 2005 which will have no impact on our results of operations or financial position.
+Property and Equipment. We follow the full-cost method of accounting for oil and gas properties
+whereby all costs incurred in connection with the acquisition, exploration and development of oil
+and gas reserves, including certain overhead costs, are capitalized into the “full-cost pool.” The
+amounts we capitalize into the full-cost pool are depleted (charged against earnings) using the
+unit-of-production method. The full-cost method of accounting for our proved oil and gas
+properties requires that we make estimates based on assumptions as to future events which could
+change. These estimates are described below.
+Depreciation, Depletion and Amortization (DD&A) of Oil and Gas Properties . We calculate depletion
+by using the capitalized costs in our full-cost pool plus future development and abandonment costs
+(combined, the depletable base) and our estimated net proved reserve quantities. Capitalized
+costs added to the full-cost pool and other costs added to the depletable base include the
+following:
+• 
+the cost of drilling and equipping productive wells, dry hole costs, acquisition costs
+of properties with proved reserves, delay rentals and other costs related to exploration
+and development of our oil and gas properties; 
+• 
+our payroll and general and administrative costs and costs related to fringe benefits
+paid to employees directly engaged in the acquisition, exploration and/or development of
+oil and gas properties as well as other directly identifiable general and administrative
+costs associated with such activities. Such capitalized costs do not include any costs
+related to our production of oil and gas or our general corporate overhead; 
+• 
+costs associated with properties that do not have proved reserves attributed to them are
+excluded from the full-cost pool. These unevaluated property costs are added to the
+full-cost pool at such time as wells are completed on the properties, the properties are
+sold or we determine these costs have been impaired. Our determination that a property has
+or has not been impaired (which is discussed below) requires that we make assumptions about
+future events; 
+• 
+our estimates of future costs to develop proved properties are added to the full-cost
+pool for purposes of the DD&A computation. We use assumptions based on the latest
+geologic, engineering, regulatory and cost data available to us to estimate these amounts.
+However, the estimates we make are subjective and may change over time. Our estimates of
+future development costs are periodically updated as additional information becomes
+available; and 
+• 
+prior to the adoption of SFAS 143, estimated costs to dismantle, abandon and restore a
+proved property were added to the full-cost pool for the purposes of DD&A. Subsequent to
+the adoption of SFAS 143, effective January 1, 2003, these costs are included in the
+full-cost pool. Such cost estimates are periodically updated as additional information
+becomes available. As discussed below, specifically SFAS
+143, beginning January 1, 2003, we changed the method for which we account for such costs. 
+Capitalized costs included in the full-cost pool are depleted and charged against earnings using
+the unit of production method. Under this method, we estimate our quantity of proved reserves at
+the beginning of each accounting period. For each barrel of oil equivalent produced during the
+period, we record a depletion
+31
+Table of Contents 
+charge equal to the amount included in the depletable base (net of
+accumulated depreciation, depletion and amortization) divided by our estimated net proved reserve
+quantities.
+Because we use estimates and assumptions to calculate proved reserves (as discussed below) and the
+amounts included in the full-cost pool, our depletion calculations will change if the estimates and
+assumptions are not realized. Such changes may be material.
+Ceiling Test . Under the full-cost accounting rules, capitalized costs included in the full-cost
+pool, net of accumulated depreciation, depletion and amortization (DD&A), cost of unevaluated
+properties and deferred income taxes, may not exceed the present value of our estimated future net
+cash flows from proved oil and gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties
+included in the costs being amortized, net of related tax effects. These rules generally require
+that, in estimating future net cash flow, we assume that future oil and gas production will be sold
+at the unescalated market price for oil and gas received at the end of each fiscal quarter and that
+future costs to produce oil and gas will remain constant at the prices in effect at the end of the
+fiscal quarter. We are required to write-down and charge to earnings the amount, if any, by which
+these costs exceed the discounted future net cash flows, unless prices recover sufficiently before
+the date of our financial statements. Given the volatility of oil and gas prices, it is likely
+that our estimates of discounted future net cash flows from proved oil and gas reserves will change
+in the near term. If oil and gas prices decline significantly, even if only for a short period of
+time, it is possible that writedowns of oil and gas properties could occur in the future.
+Estimating Reserves and Present Values . Our estimates of quantities of proved oil and gas reserves
+and the discounted present value of such reserves at the end of each quarter are based on numerous
+assumptions which are likely to change over time. These assumptions include:
+• 
+the prices at which we can sell our oil and gas production in the future. Oil and gas
+prices are volatile, but we are generally required to assume that they will not change from
+the prices in effect at the end of the quarter. In general, higher oil and gas prices will
+increase quantities of proved reserves and the present value of such reserves, while lower
+prices will decrease these amounts. Because our properties have relatively short
+productive lives, changes in prices will affect the present value more than quantities of
+oil and gas reserves; 
+• 
+the costs to develop and produce our reserves and the costs to dismantle our production
+facilities when reserves are depleted. These costs are likely to change over time, but we
+are required to assume that costs in effect at the end of the quarter will not change.
+Increases in costs will reduce oil and gas quantities and present values, while decreases
+in costs will increase such amounts. Because our properties have relatively short
+productive lives, changes in costs will affect the present value more than quantities of
+oil and gas reserves; and 
+• 
+the liability to pay royalties to the Mineral Management Service. See Note 7 of our
+Consolidated Financial Statements for a more detailed discussion of this potential
+liability. 
+In addition, the process of estimating proved oil and gas reserves requires that our independent
+and internal reserve engineers exercise judgment based on available geological, geophysical and
+technical information. We have described the risks associated with reserve estimation and the
+volatility of oil and gas prices, under “Risk Factors”.
+Unproved Properties . Costs associated with properties that do not have proved reserves, including
+capitalized interest, are excluded from the full-cost pool. These unproved properties are included
+in the line
+32
+Table of Contents 
+item “Unevaluated properties excluded from amortization.” Unproved property costs are
+transferred to the full-cost pool when wells are completed on the properties or the properties are
+sold. In addition, we are required to determine whether our unproved properties are impaired and,
+if so, add the costs of such properties to the full-cost pool. We determine whether an unproved
+property should be impaired by periodically reviewing our exploration program on a property by
+property basis. This determination may require the exercise of substantial judgment by our
+management.
+Asset Retirement Obligations. In June 2001, the FASB issued Statement of Financial Accounting
+Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”) effective for fiscal
+years beginning after June 15, 2002. SFAS 143 essentially requires entities to record the fair
+value of a liability for obligations associated with the retirement of tangible long-lived assets
+and the associated asset retirement costs. We adopted the statement on January 1, 2003 resulting in a cumulative effect of
+accounting change of $181,000, net of tax. See Note 8 to our Consolidated Financial Statements.
+Derivatives. We use derivative financial instruments for price protection purposes on a limited
+amount of our future production and do not use them for trading purposes. Such derivatives were
+accounted for in years prior to 2001 as hedges and have been recognized as an adjustment to oil and
+gas sales in the period in which they are related. We currently use the accounting treatment for
+derivatives specified under SFAS 133. 
+See Note 6 to our Consolidated Financial Statements.
+Income Taxes. We follow the asset and liability method of accounting for deferred income taxes
+prescribed by Statement of Financial Accounting Standards No. 109 (“SFAS 109”) “Accounting for
+Income Taxes”. The statement provides for the recognition of a deferred tax asset for deductible
+temporary timing differences, capital and operating loss carryforwards, statutory depletion
+carryforward and tax credit carryforwards, net of a “valuation allowance”. The valuation allowance
+is provided for that portion of the asset, for which it is deemed more likely than not, that it
+will not be realized.
+SFAS 109 provides for the weighing of positive and negative evidence in determining whether it is
+more likely than not that a deferred tax asset is recoverable. We incurred losses in 2002 and 2003
+and had losses on an aggregate basis for the three-year period ended December 31, 2003. Because of
+these cumulative losses we established a full valuation allowance of $11.5 million as of December
+31, 2003.
+As a result of production from our first two deepwater projects starting in November 2003, as well
+as refinancing our highest cost debt in 2004, we achieved profitable operations and have income on
+an aggregate basis for the three-year period ended December 31, 2004. We also expect 2005
+production levels to exceed 2004 levels and expect to utilize most if not all of the deferred tax
+asset in 2005. As a result, we have reversed the valuation allowance which had a balance of $7.0
+million as of December 31, 2004. See Note 3 to the Consolidated Financial Statements for further
+disclosure.
+33
+Table of Contents 
+Liquidity and Capital Resources 
+Our primary sources of capital are cash flows from operations, borrowings from financial
+institutions and the sale of debt and equity securities. Net cash and cash equivalents decreased
+during 2004 to $3.3 million, down $5.4 million. Cash provided from operating activities during
+2004 totaled $70.9 million, up 106% from $34.6 million in 2003. Dividends paid on preferred stock
+were $1.3 million. All of our outstanding debt was restructured during December 2003 and the first
+half of 2004. The restructuring is discussed in the following paragraphs.
+In December 2003 we borrowed $185 million pursuant to a senior unsecured credit facility with a
+stated interest rate of 9.75%. In conjunction with the new senior unsecured notes, we issued
+detachable warrants to purchase 2.775 million shares of our common stock at an exercise price of
+$10 per share and an expiration date in December 2010. This senior unsecured debt matures December 8, 2010. The net proceeds from the loans of $181.3 million were
+used to redeem $22.9 million of 10.125% senior subordinated notes due July 31, 2004 (“10.125%
+notes”), $40 million of 10.25% senior subordinated notes due September 15, 2004 (“10.25% notes”),
+$85 million of our 12% loans due March 31, 2005 (“12% loans”) plus a 1% call premium of $850,000
+and to reduce the balance outstanding under our senior secured revolving credit facility. A charge
+of $5.6 million was incurred in 2003 and a charge of approximately $1.9 million was incurred in
+2004 as a result of the early extinguishment of debt. We exercised covenant defeasance under the
+indentures for the 10.125% and 10.25% notes on December 8, 2003 and distributed a required 30-day
+redemption notice. The funds necessary to redeem the notes were placed in trust and the trustee
+paid the holders of the notes on January 8, 2004. The funds in trust were classified on our
+December 31, 2003 balance sheet as restricted cash.
+During March 2004, we borrowed an additional $15 million under our 9.75% senior unsecured credit
+facility bringing the total outstanding to $200 million. The net proceeds of approximately $14
+million were primarily used to retire the remaining $10 million of 12% loans plus a 1% call premium
+of $100,000. A charge of $559,000 was incurred as a result of early extinguishment of debt.
+In March 2004, the $200 million in aggregate principal amount of loans outstanding under the 9.75%
+senior unsecured credit facility were exchanged for 9.75% Senior Notes due 2010, Series A, “Series
+A notes”, issued pursuant to a senior indenture between us and American Stock Transfer & Trust
+Company dated March 15, 2004. On August 12, 2004, we completed an offer to exchange our 9.75%
+Senior Notes due 2010, Series B, that have been registered under the Securities Act of 1933, for
+all outstanding Series A notes. See Note 5 of our Consolidated Financial Statements for a more
+detailed description of these notes.
+On June 15, 2004, we closed on a three-year senior secured credit facility underwritten by Union
+Bank of California, N.A. The credit facility includes an initial borrowing base, determined by the
+lender, of $60 million, which may be adjusted semi-annually and could increase to a maximum of $175
+million. At closing, $21 million was advanced under the new facility for repayment of the existing
+debt under the expiring credit facility with Wachovia Bank, National Association. As of December
+31, 2004 there was $5.0 million outstanding under the facility and we had an aggregate of $2.3
+million in outstanding letters of credit issued under the credit facility. These letters of credit
+secure obligations under the outstanding hedging contracts described in Note 6 to the Consolidated
+Financial Statements. The outstanding letters of credit reduce the amount available for borrowings
+under the credit facility. As a result, $52.7 million was available for future borrowings under
+the credit facility as of December 31, 2004.
+34
+Table of Contents 
+On June 22, 2004, we closed the public offering of three million shares of common stock priced at
+$13.25 per share raising net proceeds of approximately $38.2 million, after expenses. In addition,
+we granted the underwriter, Johnson Rice & Company L.L.C., an over-allotment option to purchase an
+additional 450,000 shares. On June 30, 2004, the underwriter exercised the over-allotment option
+for an additional 450,000 shares priced at $13.25 per share, raising the net proceeds of the
+offering by approximately $5.7 million, after expenses. The proceeds from the transactions were
+used to redeem $33 million of our 11% Senior Subordinated Notes due December 15, 2005 to reduce the
+balance outstanding under our senior secured credit facility and general corporate purposes.
+Outstanding debt on
+December 31, 2004 was $192.9 million compared to $308.1 million on December 31,
+2003. Restricted cash in the amount of
+$62.9 million was used to payoff 2004 Senior Subordinated Notes
+on January 8, 2004 which were included in outstanding debt on
+December 31, 2003. The senior secured credit
+facility and our senior notes contain various covenants including restrictions on additional
+indebtedness and payment of cash dividends as well as maintenance of certain financial ratios. We
+were in compliance with these covenants at December 31, 2004.
+In December 2003, we announced the formation of a limited liability company, Medusa Spar LLC, which
+now owns a 75% undivided ownership interest in the deepwater spar production facilities on our
+Medusa Field in the Gulf of Mexico. We contributed a 15% undivided ownership interest in the
+production facility to the LLC in return for approximately $25 million in cash and a 10% ownership
+interest in the LLC. Our cash proceeds were used to reduce the balance outstanding under our senior
+secured credit facility. The LLC will earn a tariff based upon production volume throughput from
+the Medusa area. We are obligated to process our share of production from the Medusa Field and any
+future discoveries in the area through the spar production facilities. The LLC used the cash
+proceeds from $83.7 million of non-recourse financing and a cash contribution by one of the LLC
+owners to acquire its 75% interest in the spar. On December 31, 2004, $64.1 million of this
+financing was outstanding. The balance of the LLC is owned by Oceaneering International, Inc.
+(NYSE:OII) and Murphy Oil Corporation (NYSE:MUR). We are accounting for our 10% ownership interest
+in the LLC under the equity method.
+Our planned capital expenditures for 2005 total $80 million. We anticipate that cash flow
+generated during 2005 will fund these expenditures and the current portion of our asset retirement
+obligation in the amount of $13.3 million. Availability under our senior secured credit facility
+will also be available if necessary. Capitalized interest and general and administrative expenses
+are included in the $80 million. 
+Capital expenditure plans for 2005 include:
+• 
+the completion and development of two 2004 shelf discoveries; 
+• 
+the non-discretionary drilling of approximately 13 deep shelf and onshore exploratory
+wells we developed using our 3-D seismic and AVO technology; 
+• 
+drilling of a development well on our deepwater Entrada discovery; 
+• 
+drilling of two deepwater Medusa satellite prospects and one deepwater exploratory well; 
+• 
+lease and seismic acquisition; and 
+• 
+capitalized interest and overhead. 
+35
+Table of Contents 
+The following table describes our outstanding contractual obligations (in thousands) as of December
+31, 2004:
+Contractual 
+Less Than 
+One-Three 
+Four-Five 
+After-Five 
+Obligations 
+Total 
+One Year 
+Years 
+Years 
+Years 
+Senior Secured Credit Facility 
+$ 
+5,000 
+$ 
+— 
+$ 
+5,000 
+$ 
+— 
+$ 
+— 
+9.75% Senior Notes 
+200,000 
+— 
+— 
+— 
+200,000 
+Capital lease (future minimum payments) 
+2,531 
+822 
+787 
+457 
+465 
+Throughput Commitments: 
+Medusa Spar, LLC 
+17,508 
+4,824 
+6,988 
+5,696 
+— 
+Medusa Oil Pipeline 
+860 
+254 
+311 
+132 
+163 
+Hurricane Ivan 
+On September 13, 2004, several of our fields were shut-in due to Hurricane Ivan. Two of our major
+fields, Medusa which is located in Mississippi Canyon Blocks 538 and 582 and Mobile Bay Blocks 952,
+953 and 955, incurred damage as a result of the hurricane.
+The Medusa spar production facility incurred minor damage, but a platform work-over rig owned by a
+third party incurred significant damage and had to be removed from the Medusa spar production
+facility. After debris clean up and repairs, partial production was restored on October 13, 2004
+and pre-hurricane production levels were achieved by October 22, 2004.
+Mobile Bay Blocks 952, 953 and 955 incurred minor damage and wells were brought on-line as repairs
+were completed. Partial production was restored on September 24, 2004 and the field reached
+pre-hurricane production levels by October 17, 2004.
+Production from Medusa and Mobile Bay Blocks 952, 953 and 955 represented approximately 60% of our
+production for the eight months ended August 31, 2004.
+36
+Table of Contents 
+Results of Operations 
+The following table sets forth certain operating information with respect to our oil and gas
+operations for each of the three years in the period ended December 31, 2004.
+December 31, 
+2004 
+2003 
+2002(b) 
+Production: 
+Oil (MBbls) 
+1,736 
+268 
+226 
+Gas (MMcf) 
+11,387 
+12,315 
+14,215 
+Total production (MMcfe) 
+21,801 
+13,923 
+15,571 
+Average daily production (MMcfe) 
+59.6 
+38.1 
+42.7 
+Average sales price (a): 
+Oil (per Bbl) 
+$ 
+28.71 
+$ 
+28.72 
+$ 
+23.11 
+Gas (per Mcf) 
+$ 
+6.15 
+$ 
+5.36 
+$ 
+3.94 
+Total (per Mcfe) 
+$ 
+5.50 
+$ 
+5.29 
+$ 
+3.93 
+Oil and Gas revenues (in thousands): 
+Gas revenue 
+$ 
+69,976 
+$ 
+66,001 
+$ 
+55,949 
+Oil revenue 
+49,826 
+7,696 
+5,222 
+Total 
+$ 
+119,802 
+$ 
+73,697 
+$ 
+61,171 
+Oil and gas production costs (in thousands): 
+Lease operating expenses 
+$ 
+22,308 
+$ 
+11,301 
+$ 
+11,030 
+Additional per Mcfe data: 
+Sales price 
+$ 
+5.50 
+$ 
+5.29 
+$ 
+3.93 
+Lease operating expenses 
+1.02 
+.81 
+.71 
+Operating margin 
+$ 
+4.48 
+$ 
+4.48 
+$ 
+3.22 
+Depletion 
+$ 
+2.18 
+$ 
+2.03 
+$ 
+1.73 
+Accretion 
+$ 
+.16 
+$ 
+.21 
+$ 
+— 
+General and administrative (net of management fees) 
+$ 
+.40 
+$ 
+.34 
+$ 
+.30 
+(a) 
+Average sales price includes hedging gains and losses. 
+(b) 
+Production volumes include 1,200 MMcf for the year 2002 at an average price of $2.08 per Mcf
+associated with a volumetric production payment. 
+37
+Table of Contents 
+Off-Balance Sheet Arrangements 
+In December 2003, we announced the formation of a limited liability company, Medusa Spar LLC, which
+now owns a 75% undivided ownership interest in the deepwater spar production facilities on our
+Medusa Field in the Gulf of Mexico. We contributed a 15% undivided ownership interest in the
+production facility to Medusa Spar LLC in return for approximately $25 million in cash and a 10%
+ownership interest in the LLC. The LLC will earn a tariff based upon production volume throughput
+from the Medusa area. We are obligated to process our share of production from the Medusa Field and
+any future discoveries in the area through the spar production facilities. This arrangement allows
+us to defer the cost of the spar production facility over the life of the Medusa Field. Our cash
+proceeds were used to reduce the balance outstanding under our senior secured credit facility. The
+LLC used the cash proceeds from $83.7 million of non-recourse financing and a cash contribution by
+one of the LLC owners to acquire its 75% interest in the spar. On December 31, 2004, $64.1 million
+of the financing was outstanding. The balance of Medusa Spar LLC is owned by Oceaneering
+International, Inc. (NYSE:OII) and Murphy Oil Corporation (NYSE:MUR). We are accounting for our
+10% ownership interest in the LLC under the equity method.
+Comparison of Results of Operations for the Years Ended December 31, 2004 and 2003 
+Oil and Gas Revenues 
+Total production for 2004 increased by 57% versus 2003 and total oil and gas revenues increased 63%
+from $73.7 million in 2003 to $119.8 million in 2004. Increased production was primarily due to our
+deepwater discoveries, Medusa and Habanero, which began producing late in the fourth quarter of
+2003.
+Gas production during 2004 totaled 11.4 Bcf and generated $70.0 million in revenues compared to
+12.3 Bcf and $66.0 million in revenues during the same period in 2003. Average gas prices realized
+for 2004 were $6.15 per Mcf compared to $5.36 per Mcf during the same period last year. The
+decrease in production was primarily due to downtime for Hurricane Ivan and the normal and expected
+decline in production from our Mobile area fields and older properties. These factors were
+partially offset by production from Medusa and Habanero.
+Oil production during 2004 totaled 1,736,000 barrels and generated $49.8 million in revenues
+compared to 268,000 barrels and $7.7 million in revenues for the same period in 2003. Average oil
+prices realized in 2004 were $28.71 per barrel compared to $28.72 per barrel in 2003. The increase
+in production was due to the initial production from our deepwater discoveries, Medusa and
+Habanero, which began producing late in the fourth quarter of 2003. The production increase was
+offset slightly by downtime for Hurricane Ivan and normal and expected declines in production from
+older properties.
+Lease Operating Expenses 
+Lease operating expenses for 2004 increased by 97% to $22.3 million compared to $11.3 million for
+the same period in 2003. The increase was primarily due to lease operating expenses related to our
+deepwater discoveries, Medusa and Habanero, which began producing late in the fourth quarter of
+2003.
+Depreciation, Depletion and Amortization 
+Depreciation, depletion and amortization for 2004 and 2003 were $47.5 million and $28.3 million,
+respectively. The 68% increase was primarily due to higher production volumes for 2004 compared to
+2003.
+38
+Table of Contents 
+Accretion Expense 
+Accretion expense for 2004 and 2003 of $3.4 million and $2.9 million, respectively, represents
+accretion for our asset retirement obligations. The increase was due to the addition of plugging
+and abandonment obligations. See Note 8 to the Consolidated Financial Statements.
+General and Administrative 
+General and administrative expenses for 2004, net of amounts capitalized, were $8.8 million
+compared to $4.7 million incurred in 2003. There was a charge in general and administrative
+expenses of $2.6 million in the first quarter of 2004 for the early retirement of two executive
+officers of the Company. Also reduced capitalized overhead, higher
+directors’ fees, and increased independent and internal audit
+costs resulting from implementation of Sarbanes – Oxley 404 contributed to the increase in general and administrative
+expenses.
+Interest Expense 
+Interest expense decreased by 34% in 2004 to $20.1 million compared to $30.6 million in 2003. This
+is a result of lower debt levels and lower interest rates due to the restructuring of debt in
+December 2003 and during the six-month period ended June 30, 2004 in additional to an equity offering completed in
+the second quarter of 2004. In addition, amortization of deferred financing costs and bond
+discounts decreased due to the write-off of unamortized deferred financing costs and bond discounts
+associated with the early extinguishment of debt.
+Loss on Early Extinguishment of Debt 
+A loss of $3.0 million and $5.6 million was incurred in 2004 and 2003, respectively. Both were
+incurred for the write-off of deferred financing costs, pre-payment premiums and bond discounts
+associated with the early extinguishment of debt.
+Income Taxes 
+The income tax benefit of $6.7 million in 2004 resulted primarily from the reversal of the
+valuation allowance established in 2003 against our deferred tax asset. As a result of production
+from our first two deepwater projects starting in November 2003, as well as refinancing its highest cost debt in 2004, we
+achieved profitable operations and have income on an aggregate basis for the three-year period ended December 31, 2004. Callon also expects 2005 production levels
+to exceed 2004 levels and expects to utilize most if not all of the deferred tax asset in 2005. As a result, we reversed the valuation allowance.
+See Note 3 to our Consolidated Financial Statements for a more detailed discussion.
+Comparison of Results of Operations for the Years Ended December 31, 2003 and 2002 
+Oil and Gas Revenues 
+Total oil and gas revenues increased 20% from $61.2 million in 2002 to $73.7 million in 2003 while
+total production for 2003 decreased by 11% versus 2002. Realized oil and gas prices were
+substantially higher when compared to the same period in 2002 and accounted for the increase in
+revenue. Gas revenues for 2002 included $9.2 million of non-cash revenue related to the Enron
+derivatives discussed in Note 6 to the Consolidated Financial Statements.
+Gas production during 2003 totaled 12.3 Bcf and generated $66.0 million in revenues compared to
+14.2 Bcf and $55.9 million in revenues during the same period in 2002. Average gas prices for 2003
+were $5.36 per Mcf compared to $3.94 per Mcf during the same period in 2002. The decrease in
+production was primarily
+39
+Table of Contents 
+due to the depletion of the lowest productive zone of the East Cameron
+Block 294 field. The well at East Cameron Block 294 was returned to production after a
+recompletion to a behind pipe zone in the third quarter of 2003. Also, the sale of the North and
+Northwest Dauphin Island fields in the fourth quarter of 2002 and the normal and expected declines
+in production from other properties contributed to the variance.
+Oil production during 2003 totaled 268,000 barrels and generated $7.7 million in revenues compared
+to 226,000 barrels and $5.2 million in revenues for the same period in 2002. Average oil prices
+received in 2003 were $28.72 per barrel compared to $23.11 per barrel in 2002. The increase in
+production was due to the initial production from our deepwater discoveries, Medusa and Habanero,
+which began producing late in the fourth quarter of 2003. This was offset slightly by downtime for
+maintenance to the facility and equipment at the Big Escambia Creek Field formally operated by
+ExxonMobil Corporation, currently operated by Vintage, and normal and expected declines in
+production from older properties.
+Lease Operating Expenses 
+Lease operating expenses for 2003 increased by 2% to $11.3 million compared to $11.0 million for
+the same period in 2002. The increase was primarily due to the increase in lease operating
+expenses for the Mobile Block 864 area resulting from the implementation of the accelerated
+production program in the second quarter of 2002 and lease operating expenses related to our
+deepwater discoveries, Medusa and Habanero, which began producing late in the fourth quarter of
+2003. The increase was slightly offset as a result of the
+sale of North and Northwest Dauphin Island fields in the fourth quarter of 2002 which reduced lease
+operating expenses for 2003.
+Depreciation, Depletion and Amortization 
+Depreciation, depletion and amortization for 2003 and 2002 were $28.3 million and $27.1 million,
+respectively. The 4% increase was due primarily to the downward reserve revisions for our
+Boomslang Field at Ewing Bank Block 994 at the end of 2002. This decrease in estimated proved
+reserves increased the depletable cost per unit of production.
+Accretion Expense 
+Accretion expense of $2.9 million represents accretion for our asset retirement obligations for
+2003.
+General and Administrative 
+General and administrative expenses for 2003, net of amounts capitalized, were $4.7 million and
+flat with the amount incurred in 2002.
+Interest Expense 
+Interest expense increased by 17% in 2003 to $30.6 million compared to $26.1 million in 2002. This
+was a result of higher debt levels.
+40
+Table of Contents 
+Loss on Early Extinguishment of Debt 
+A loss of $5.6 million was incurred in December of 2003 for the write-off of deferred financing
+costs and bond discounts associated with the early extinguishment of $85 million of the 12% loans
+due in 2005 plus a 1% pre-payment premium.
+Income Taxes 
+The income tax expense of $8.4 million in 2003 was primarily due to a charge of $11.5 million to
+establish a valuation allowance against our deferred tax asset.
+We incurred losses in 2002 and 2003 and had losses on an
+aggregate basis for the three-year period ended December 31, 2003.
+Because of these cumulative losses we established a full valuation allowance.
+See Note 3
+to our Consolidated Financial Statements for a more detailed discussion.
+41
+Table of Contents 
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS 
+The Company’s revenues are derived from the sale of its crude oil and natural gas production. In
+recent months, the prices for oil and gas have increased; however, they remain extremely volatile
+and sometimes experience large fluctuations as a result of relatively small changes in supplies,
+weather conditions, economic conditions and government actions. The Company enters into derivative
+financial instruments to hedge oil and gas price risks for the production volumes to which the
+hedge relates. The derivatives reduce the Company’s exposure on the hedged volumes to decreases in
+commodity prices and limit the benefit the Company might otherwise have received from any increases
+in commodity prices on the hedged volumes.
+The Company also enters into price “collars” to reduce the risk of changes in oil and gas prices.
+Under these arrangements, no payments are due by either party so long as the market price is above
+the floor price set in the collar and below the ceiling. If the price falls below the floor, the
+counter-party to the collar pays the difference to the Company and if the price is above the
+ceiling, the counter-party receives the difference from the Company. Another type of hedging
+contract Callon has entered into is a put contract. Under a put, if the price falls below the set
+floor price, the counter-party to the contract pays the difference to the Company. The Company
+enters into these various agreements to reduce the effects of volatile oil and gas prices and does
+not enter into hedge transactions for speculative purposes. See Note 6 to the Consolidated
+Financial Statements for a description of the Company’s hedged position at December
+31, 2004. There have been no significant changes in market risks faced by the Company since the
+end of 2004.
+Based on projected annual sales volumes for 2005 (excluding forecast production increases over
+2004), a 10% decline in the prices Callon receives for its crude oil and natural gas production
+would have an approximate $13.3 million impact on our revenues.
+42
+Table of Contents 
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+Page 
+Report of Independent Registered Public Accounting Firm 
+44 
+Consolidated Balance Sheets as of December 31, 2004
+and 2003 
+45 
+Consolidated Statements of Operations for Each of the Three Years
+in the Period Ended December 31, 2004 
+46 
+Consolidated Statements of Stockholders’ Equity
+for Each of the Three Years in the Period Ended December 31, 2004 
+47 
+Consolidated Statements of Cash Flows for Each of the Three Years
+in the Period Ended December 31, 2004 
+48 
+Notes to Consolidated Financial Statements 
+49 
+43
+Table of Contents 
+Report of Independent Registered Public Accounting Firm
+The Stockholders and Board of Directors 
+Callon Petroleum Company
+We have audited the accompanying consolidated balance sheets of Callon Petroleum Company as of
+December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’
+equity and cash flows for each of the three years in the period ended December 31, 2004. These
+financial statements are the responsibility of the Company’s management. Our responsibility is to
+express an opinion on these financial statements based on our audits.
+We conducted our audits in accordance with the standards of the Public Company Accounting
+Oversight Board (United States). Those standards require that we plan and perform the audit to
+obtain reasonable assurance about whether the financial statements are free of material
+misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
+disclosures in the financial statements. An audit also includes assessing the accounting
+principles used and significant estimates made by management, as well as evaluating the overall
+financial statement presentation. We believe that our audits provide a reasonable basis for our
+opinion.
+In our opinion, the financial statements referred to above present fairly, in all material
+respects, the consolidated financial position of Callon Petroleum Company as of December 31, 2004
+and 2003, and the results of its operations and its cash flows for each of the three years in the
+period ended December 31, 2004, in conformity with accounting principles generally accepted in the
+United States.
+As discussed in Note 1 to the financial statements, effective January 1, 2003, the Company
+adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement
+Obligations”.
+We also have audited, in accordance with the standards of the Public Company Accounting
+Oversight Board (United States), the effectiveness of Callon Petroleum Company’s internal control
+over financial reporting as of December 31, 2004, based on criteria established in Internal
+Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
+Commission and our report dated March 8, 2005, expressed an unqualified opinion thereon.
+/s/Ernst & Young LLP 
+New Orleans, Louisiana 
+March 8, 2005
+44
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED BALANCE SHEETS 
+(In thousands, except share data) 
+December 31, 
+2004 
+2003 
+ASSETS 
+Current assets: 
+Cash and cash equivalents 
+$ 
+3,266 
+$ 
+8,700 
+Restricted cash 
+— 
+63,345 
+Accounts receivable 
+14,928 
+10,117 
+Deferred tax asset-current 
+5,676 
+— 
+Restricted investments-current 
+2,055 
+— 
+Fair market value
+of derivatives 
+1,570 
+— 
+Other current assets 
+581 
+3,606 
+Total current assets 
+28,076 
+85,768 
+Oil and gas properties, full-cost accounting method: 
+Evaluated properties 
+862,101 
+802,912 
+Less accumulated depreciation, depletion and amortization 
+(494,453 
+) 
+(447,000 
+) 
+367,648 
+355,912 
+Unevaluated properties excluded from amortization 
+39,042 
+34,251 
+Total oil and gas properties 
+406,690 
+390,163 
+Other property and equipment, net 
+1,541 
+1,547 
+Deferred tax asset 
+2,986 
+— 
+Long-term gas balancing receivable 
+725 
+1,101 
+Restricted investments 
+5,687 
+7,420 
+Investment in Medusa Spar LLC 
+9,787 
+8,471 
+Other assets, net 
+2,031 
+1,562 
+Total assets 
+$ 
+457,523 
+$ 
+496,032 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued liabilities 
+$ 
+15,728 
+$ 
+15,855 
+Fair market
+value of derivatives 
+2,993 
+165 
+Undistributed oil and gas revenues 
+1,162 
+897 
+Accrued net profits interest payable 
+1,927 
+1,886 
+Suspended
+Medusa oil royalties 
+5,430 
+— 
+Asset retirement obligations-current 
+13,300 
+8,571 
+Current maturities of long-term debt 
+576 
+93,223 
+Total current liabilities 
+41,116 
+120,597 
+Long-term debt 
+192,351 
+214,885 
+Asset retirement obligations 
+24,982 
+25,120 
+Other long-term liabilities 
+762 
+2,169 
+Total liabilities 
+259,211 
+362,771 
+Stockholders’ equity: 
+Preferred Stock, $.01 par value; 2,500,000 shares authorized;
+596,671 shares of Convertible Exchangeable Preferred Stock,
+Series A issued and outstanding at December 31, 2004
+with a liquidation preference of $14,916,775 
+6 
+6 
+Common Stock, $.01 par value; 30,000,000 shares
+authorized; 17,616,596 shares and 13,935,311 shares
+outstanding at December 31, 2004 and 2003, respectively 
+176 
+139 
+Unearned compensation-restricted stock 
+(5,352 
+) 
+(372 
+) 
+Capital in excess of par value 
+220,664 
+169,036 
+Other comprehensive loss 
+(1,883 
+) 
+(20 
+) 
+Retained earnings (deficit) 
+(15,299 
+) 
+(35,528 
+) 
+Total stockholders’ equity 
+198,312 
+133,261 
+Total liabilities and stockholders’ equity 
+$ 
+457,523 
+$ 
+496,032 
+The accompanying notes are an integral part of these financial statements.
+45
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Statements of Operations 
+For the Years Ended December 31, 2004, 2003 and 2002 
+(In thousands, except per share amounts) 
+2004 
+2003 
+2002 
+Operating revenues: 
+Oil and gas sales 
+$ 
+119,802 
+$ 
+73,697 
+$ 
+61,171 
+Operating expenses: 
+Lease operating expenses 
+22,308 
+11,301 
+11,030 
+Depreciation, depletion and amortization 
+47,453 
+28,253 
+27,096 
+General and administrative 
+8,758 
+4,713 
+4,705 
+Accretion expense 
+3,400 
+2,884 
+— 
+Derivative expense 
+1,371 
+535 
+708 
+Total operating expenses 
+83,290 
+47,686 
+43,539 
+Income from operations 
+36,512 
+26,011 
+17,632 
+Other (income) expenses: 
+Interest expense 
+20,137 
+30,614 
+26,140 
+Other (income) 
+(357 
+) 
+(444 
+) 
+(1,004 
+) 
+Loss on early extinguishment of debt 
+3,004 
+5,573 
+— 
+Gain on sale of pipeline 
+— 
+— 
+(2,454 
+) 
+Gain on sale of Enron derivatives 
+— 
+— 
+(2,479 
+) 
+Total other (income) expenses 
+22,784 
+35,743 
+20,203 
+Income (loss) before income taxes 
+13,728 
+(9,732 
+) 
+(2,571 
+) 
+Income tax expense (benefit) 
+(6,697 
+) 
+8,432 
+(900 
+) 
+Income (loss) before Medusa Spar LLC and cumulative
+effect of change in accounting principle 
+20,425 
+(18,164 
+) 
+(1,671 
+) 
+Income (loss) on Medusa Spar LLC, net of tax 
+1,076 
+(8 
+) 
+— 
+Income (loss) before cumulative effect of change in
+accounting principle 
+21,501 
+(18,172 
+) 
+(1,671 
+) 
+Cumulative effect of change in accounting principle, net of tax 
+— 
+181 
+— 
+Net income (loss) 
+21,501 
+(17,991 
+) 
+(1,671 
+) 
+Preferred stock dividends 
+1,272 
+1,277 
+1,277 
+Net income (loss) available to common shares 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+$ 
+(2,948 
+) 
+Net income (loss) per common share: 
+Basic
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+1.28 
+$ 
+(1.42 
+) 
+$ 
+(0.22 
+) 
+Cumulative effect of change in accounting principle, net of
+tax 
+— 
+0.01 
+— 
+Net income (loss) available to common 
+$ 
+1.28 
+$ 
+(1.41 
+) 
+$ 
+(0.22 
+) 
+Diluted
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+1.22 
+$ 
+(1.42 
+) 
+$ 
+(0.22 
+) 
+Cumulative effect of change in accounting principle, net of
+tax 
+— 
+0.01 
+— 
+Net income (loss) available to common 
+$ 
+1.22 
+$ 
+(1.41 
+) 
+$ 
+(0.22 
+) 
+Shares used in computing net income (loss): 
+Basic 
+15,796 
+13,662 
+13,387 
+Diluted 
+17,678 
+13,662 
+13,387 
+The accompanying notes are an integral part of these financial statements.
+46
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY 
+(In thousands) 
+Unearned 
+Accumulated 
+Total 
+Restricted 
+Capital in 
+Other 
+Retained 
+Stock- 
+Preferred 
+Common 
+Stock 
+Excess of 
+Comprehensive 
+Earnings 
+holders’ 
+Stock 
+Stock 
+Compensation 
+Par Value 
+Income (Loss) 
+(Deficit) 
+Equity 
+Balances, December 31, 2001 
+$ 
+6 
+$ 
+134 
+$ 
+— 
+$ 
+154,425 
+$ 
+5,971 
+$ 
+(13,312 
+) 
+$ 
+147,224 
+Comprehensive income (loss): 
+Net loss 
+— 
+— 
+— 
+— 
+— 
+(1,671 
+) 
+Other comprehensive loss 
+— 
+— 
+— 
+— 
+(6,440 
+) 
+— 
+Total comprehensive loss 
+(8,111 
+) 
+Preferred stock dividends 
+— 
+— 
+— 
+— 
+— 
+(1,277 
+) 
+(1,277 
+) 
+Shares issued pursuant to employee
+benefit and option plan 
+— 
+1 
+— 
+770 
+— 
+— 
+771 
+Employee stock purchase plan 
+— 
+— 
+— 
+79 
+— 
+— 
+79 
+Tax benefits related to stock
+compensation plans 
+— 
+— 
+— 
+(29 
+) 
+— 
+— 
+(29 
+) 
+Restricted stock 
+— 
+3 
+(826 
+) 
+1,849 
+— 
+— 
+1,026 
+Warrants 
+— 
+1 
+— 
+1,276 
+— 
+— 
+1,277 
+Balances, December 31, 2002 
+6 
+139 
+(826 
+) 
+158,370 
+(469 
+) 
+(16,260 
+) 
+140,960 
+Comprehensive income (loss): 
+Net loss 
+— 
+— 
+— 
+— 
+— 
+(17,991 
+) 
+Other comprehensive income 
+— 
+— 
+— 
+— 
+449 
+— 
+Total comprehensive loss 
+(17,542 
+) 
+Preferred stock dividends 
+— 
+— 
+— 
+— 
+— 
+(1,277 
+) 
+(1,277 
+) 
+Shares issued pursuant to employee
+benefit and option plan 
+— 
+1 
+— 
+427 
+— 
+— 
+428 
+Employee stock purchase plan 
+— 
+— 
+— 
+127 
+— 
+— 
+127 
+Restricted stock 
+— 
+(1 
+) 
+454 
+(516 
+) 
+— 
+— 
+(63 
+) 
+Warrants 
+— 
+— 
+— 
+10,628 
+— 
+— 
+10,628 
+Balances, December 31, 2003 
+6 
+139 
+(372 
+) 
+169,036 
+(20 
+) 
+(35,528 
+) 
+133,261 
+Comprehensive income (loss): 
+Net income 
+— 
+— 
+— 
+— 
+— 
+21,501 
+Other comprehensive (loss) 
+— 
+— 
+— 
+— 
+(1,863 
+) 
+— 
+Total comprehensive income 
+19,638 
+Preferred stock dividend 
+— 
+— 
+— 
+— 
+— 
+(1,272 
+) 
+(1,272 
+) 
+Sale of common stock 
+— 
+35 
+— 
+44,012 
+— 
+— 
+44,047 
+Shares issued pursuant to employee
+benefit and option plan 
+— 
+1 
+— 
+720 
+— 
+— 
+721 
+Employee stock purchase plan 
+— 
+1 
+— 
+208 
+— 
+— 
+209 
+Tax benefits related to stock
+compensation plans 
+— 
+— 
+— 
+1,214 
+— 
+— 
+1,214 
+Restricted stock 
+— 
+— 
+(4,980 
+) 
+5,474 
+— 
+— 
+494 
+Balances, December 31, 2004 
+$ 
+6 
+$ 
+176 
+$ 
+(5,352 
+) 
+$ 
+220,664 
+$ 
+(1,883 
+) 
+$ 
+(15,299 
+) 
+$ 
+198,312 
+The accompanying notes are an integral part of these financial statements.
+47
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+For the Years Ended December 31, 2004, 2003 and 2002 
+(In thousands) 
+2004 
+2003 
+2002 
+Cash flows from operating activities: 
+Net income (loss) 
+$ 
+21,501 
+$ 
+(17,991 
+) 
+$ 
+(1,671 
+) 
+Adjustments to reconcile net income (loss) to
+cash provided by operating activities: 
+Depreciation, depletion and amortization 
+48,164 
+29,264 
+27,774 
+Accretion expense 
+3,400 
+2,884 
+— 
+Amortization of deferred financing costs 
+1,929 
+6,568 
+5,521 
+Non-cash loss on extinguishment of debt 
+2,910 
+4,423 
+Amortization of deferred production payment revenue 
+— 
+— 
+(2,406 
+) 
+Income from investment in Medusa Spar, LLC 
+(1,076 
+) 
+— 
+— 
+Cumulative effect of change in accounting principle 
+— 
+(181 
+) 
+— 
+Non-cash derivative income 
+— 
+— 
+(9,186 
+) 
+Non-cash
+derivative expense 
+(135 
+) 
+487 
+708 
+Deferred income tax expense (benefit) 
+(6,697 
+) 
+8,432 
+(900 
+) 
+Gain on sale of pipeline 
+— 
+— 
+(2,454 
+) 
+Non-cash charge related to compensation plans 
+1,225 
+858 
+1,267 
+Changes in current assets and liabilities: 
+Accounts receivable, trade 
+(4,495 
+) 
+(1,438 
+) 
+(4,967 
+) 
+Other current assets 
+971 
+(2,667 
+) 
+(104 
+) 
+Current liabilities 
+2,903 
+5,185 
+3,198 
+Investment in derivative contracts 
+— 
+— 
+(1,687 
+) 
+Change in gas balancing receivable 
+376 
+(340 
+) 
+(288 
+) 
+Change in gas balancing payable 
+400 
+(491 
+) 
+(390 
+) 
+Change in other long-term liabilities 
+(20 
+) 
+(15 
+) 
+67 
+Change in other assets, net 
+(448 
+) 
+(349 
+) 
+(2,315 
+) 
+Cash provided (used) by operating activities 
+70,908 
+34,629 
+12,167 
+Cash flows from investing activities: 
+Capital expenditures 
+(64,649 
+) 
+(50,705 
+) 
+(66,023 
+) 
+Distribution from Medusa Spar, LLC 
+339 
+24,908 
+— 
+Proceeds from sale of pipeline and other facilities 
+— 
+1,500 
+6,784 
+Proceeds from sale of mineral interests 
+— 
+982 
+4,492 
+Cash provided (used) by investing activities 
+(64,310 
+) 
+(23,315 
+) 
+(54,747 
+) 
+Cash flows from financing activities: 
+Change in accounts payable and accrued liability to be refinanced 
+— 
+(3,861 
+) 
+(5,697 
+) 
+Increase in debt 
+90,000 
+198,000 
+109,900 
+Payments on debt 
+(205,915 
+) 
+(133,000 
+) 
+(58,085 
+) 
+Restricted cash 
+63,345 
+(63,345 
+) 
+— 
+Debt issuance cost 
+(984 
+) 
+(3,745 
+) 
+(2,291 
+) 
+Issuance of common stock 
+44,047 
+— 
+— 
+Equity issued related to employee stock plans 
+199 
+127 
+79 
+Capital leases 
+(1,452 
+) 
+(1,320 
+) 
+(1,129 
+) 
+Cash dividends on preferred stock 
+(1,272 
+) 
+(1,277 
+) 
+(1,277 
+) 
+Cash provided (used) by financing activities 
+(12,032 
+) 
+(8,421 
+) 
+41,500 
+Net increase (decrease) in cash and cash equivalents 
+(5,434 
+) 
+2,893 
+(1,080 
+) 
+Cash and short-term investments: 
+Balance, beginning of period 
+8,700 
+5,807 
+6,887 
+Balance, end of period 
+$ 
+3,266 
+$ 
+8,700 
+$ 
+5,807 
+The accompanying notes are an integral part of these financial statements.
+48
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+1. ORGANIZATION 
+General 
+Callon Petroleum Company (“the Company” or “Callon”) was organized under the laws of the state of
+Delaware in March 1994 to serve as the surviving entity in the consolidation and combination of
+several related entities (referred to herein collectively as the “Constituent Entities”). The
+combination of the businesses and properties of the Constituent Entities with the Company was
+completed on September 16, 1994 (“Consolidation”).
+As a result of the Consolidation, all of the businesses and properties of the Constituent Entities
+are owned (directly or indirectly) by the Company. Certain registration rights were granted to the
+stockholders of certain of the Constituent Entities. See Note 7.
+The Company and its predecessors have been engaged in the acquisition, development and exploration
+of crude oil and natural gas since 1950. The Company’s properties are geographically concentrated
+in Louisiana, Alabama and offshore Gulf of Mexico.
+2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 
+Principles of Consolidation and Reporting 
+The Consolidated Financial Statements include the accounts of the Company, and its subsidiary,
+Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries, namely Callon Offshore
+Production, Inc. and Mississippi Marketing, Inc. All intercompany accounts and transactions have
+been eliminated. Certain prior year amounts have been reclassified to conform to presentation in
+the current year.
+Use of Estimates 
+The preparation of financial statements in conformity with generally accepted accounting principles
+requires management to make estimates and assumptions that affect the reported amounts of assets
+and liabilities and disclosure of contingent assets and liabilities at the date of the financial
+statements and the reported amounts of revenues and expenses during the reporting period. Actual
+results could differ from those estimates.
+Accounting Pronouncements 
+On December 16, 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised
+2004), (“SFAS 123R”) Share-Based Payment, which is a revision of Statement of Financial Accounting
+Standards No. 123, (“SFAS 123”) Accounting for Stock-Based Compensation . SFAS 123R supersedes APB
+Opinion No. 25, Accounting for Stock Issued to Employees , and amends Statement of Financial
+Accounting Standards No. 95, Statement of Cash Flows . Generally, the approach in SFAS 123R is
+similar to the approach described in SFAS 123. However, SFAS 123R requires all share-based
+payments to
+49
+Table of Contents 
+employees, including grants of employee stock options, to be recognized in the income
+statement based on their fair values. Pro forma disclosure is no longer an alternative.
+SFAS 123R must be adopted no later than July 1, 2005. Early adoption will be permitted in periods
+in which financial statements have not yet been issued. SFAS 123R permits public companies to
+adopt its requirements using one of two methods below:
+• 
+A “modified prospective” method in which compensation cost is recognized beginning with
+the effective date (a) based on the requirements of SFAS 123R for all share-based payments
+granted after the effective date and (b) based on the requirements of SFAS 123 for all
+awards granted to employees prior to the effective date of SFAS 123R that remain unvested
+on the effective date; or 
+• 
+A “modified retrospective” method which includes the requirements of the modified
+prospective method described above, but also permits entities to restate based on the
+amounts previously recognized under SFAS 123 for purposes of pro forma disclosures either
+(a) all prior periods presented or (b) prior interim periods of the year of adoption. 
+The Company expects to adopt SFAS 123R on July 1, 2005 using the modified prospective method.
+As permitted by SFAS 123, the Company currently accounts for share-based payments to employees
+using Opinion 25’s intrinsic value method and, as such, generally recognizes no compensation cost
+for employee stock options. Accordingly, the adoption of SFAS 123R’s fair value method will have a
+significant impact on our result of operations, although it will have no impact on our overall
+financial position. The impact of adoption of SFAS 123R cannot be predicted at this time because
+it will depend on levels of share-based payments granted in the future. However, had we adopted
+SFAS 123R in prior periods, the impact of that standard would have approximated the impact of SFAS
+123 as described in the disclosure of pro forma net income and earnings per share below under
+Stock-Based Compensation.
+In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest
+Entities, an Interpretation of Accounting Research Bulletin (ARB) 51” (“FIN 46”). FIN 46 addresses
+consolidation by business enterprises of variable interest entities (“VIEs”). The primary
+objective of FIN 46 is to provide guidance on the identification of, and financial reporting for,
+entities over which control is achieved through means other than voting rights; such entities are
+known as VIEs. The Company adopted FIN 46, as revised, as of December 31, 2003, which had no
+impact on the Company’s results of operations or financial position.
+In September 2004, the Securities and Exchange Commission issued Staff Accounting Bulletin (“SAB”)
+No. 106 which expressed the Staff’s views regarding the application of Statement of Financial
+Accounting Standards (“SFAS”) No. 143 “Accounting for Asset Retirement Obligations” by oil and gas
+producing companies following the full-cost accounting method. SAB No. 106 specifies that
+subsequent to the adoption of SFAS No. 143 an oil and gas company following the full-cost method of
+accounting should include assets recorded in connection with the recognition of an asset retirement
+obligation pursuant to SFAS No. 143 as part of the costs subject to the full-cost ceiling
+limitation. The future cash outflows associated with settling the recorded asset retirement
+obligations should be excluded from the computation of the present value of estimated future net
+revenues used in applying the ceiling test. The Company will be required to adopt the provisions
+of SAB No. 106 prospectively in the first quarter of 2005 which will have no impact on the
+Company’s results of operation or financial position.
+Property and Equipment 
+The Company follows the full-cost method of accounting for oil and gas properties whereby all costs
+incurred in connection with the acquisition, exploration and development of oil and gas reserves,
+including
+50
+Table of Contents 
+certain overhead costs, are capitalized. Such amounts include the cost of drilling and
+equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest
+capitalized on unevaluated leases and other costs related to exploration and development
+activities. General and administrative costs capitalized include salaries and related fringe
+benefits paid to employees directly engaged in the acquisition, exploration and/or development of
+oil and gas properties as well as other directly identifiable general and administrative costs
+associated with such activities. Such capitalized costs ($7.2 million in 2004, $8.4 million in
+2003 and $9.6 million in 2002) do not include any costs related to production or general corporate
+overhead. Costs associated with unevaluated properties, including capitalized interest on such
+costs, are excluded from amortization. Unevaluated property costs are transferred to evaluated
+property costs at such time as wells are completed on the properties, the properties are sold or
+management determines that these costs have been impaired.
+Costs of properties, including future development and future site restoration, dismantlement and
+abandonment costs, which have proved reserves and properties which have been determined to be
+worthless, are depleted using the unit-of-production method based on proved reserves. If the total
+capitalized costs of oil and gas properties, net of accumulated amortization and deferred taxes
+relating to oil and gas properties, exceed the sum of (1) the estimated future net revenues from
+proved reserves at current prices and discounted at 10% and (2) the lower of cost or market of
+unevaluated properties (the full-cost ceiling amount), net of tax effects, then such excess is
+charged to expense during the period in which the excess occurs. See Note 9.
+Upon the acquisition or discovery of oil and gas properties, management estimates the future net
+costs to be incurred to dismantle, abandon and restore the property using available geological,
+engineering and regulatory data. Such cost estimates are periodically updated for changes in
+conditions and requirements. Such estimated amounts are considered as part of the full-cost pool
+subject to amortization upon acquisition or discovery. Until January 1, 2003, such costs were
+capitalized as oil and gas properties as the actual restoration, dismantlement and abandonment
+activities took place. As discussed below under Asset Retirement Obligations, beginning January 1,
+2003, the Company changed the method for which we account for such costs upon adoption of SFAS 143
+and these costs are now included in the full cost pool. For purposes of the full-cost ceiling
+test, the Company nets the Asset Retirement Obligation liability against the net capitalized costs
+of oil and gas properties and includes the future cash outflows associated with asset retirement
+obligations in the valuation of the full-cost ceiling amount.
+Depreciation of other property and equipment is provided using the straight-line method over
+estimated lives of three to 20 years. Depreciation of pipeline and other facilities is provided
+using the straight-line method over estimated lives of 15 to 27 years. Depreciation expense of
+$346,000, $578,000 and $696,000 relating to other property and equipment was included in general
+and administrative expenses in the Company’s statements of operations for the years ended December
+31, 2004, 2003 and 2002, respectively. The accumulated depreciation on other property and
+equipment was $10.4 million and $10.2 million as of December 31, 2004 and 2003, respectively.
+Investment in Medusa Spar LLC 
+In December 2003, the Company announced the formation of a limited liability company, Medusa Spar
+LLC, which now owns a 75% undivided ownership interest in the deepwater spar production facilities
+on Callon’s Medusa Field in the Gulf of Mexico. The Company contributed a 15% undivided ownership
+interest in the production facility to Medusa Spar LLC in return for approximately $25 million in
+cash and a 10% ownership interest in the LLC. The LLC will earn a tariff based upon production
+volume throughput from the Medusa area. Callon is obligated to process our share of production from
+the Medusa
+51
+Table of Contents 
+Field and any future discoveries in the area through the spar production facilities.
+This arrangement allows Callon to defer the cost of the spar production facility over the life of
+the Medusa Field. The Company’s cash proceeds were used to reduce the balance outstanding under
+its senior secured credit facility. The LLC used the cash proceeds from $83.7 million of
+non-recourse financing and a cash contribution by one of the LLC owners to acquire its 75% interest
+in the spar. On December 31, 2004, $64.1 million of the financing was outstanding. The balance of
+Medusa Spar LLC is owned by Oceaneering International, Inc. (NYSE:OII) and Murphy Oil Corporation
+(NYSE:MUR). The Company is accounting for our 10% ownership interest in the LLC under the equity
+method.
+Asset Retirement Obligations 
+In June 2001, the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for
+Asset Retirement Obligations (“SFAS 143”) effective for fiscal years beginning after June 15, 2002.
+SFAS 143 essentially requires entities to record the fair value of a liability for obligations
+associated with the retirement of tangible long-lived assets and the associated asset retirement
+costs. Callon adopted SFAS 143 on January 1, 2003 resulting in a cumulative effect of accounting
+change of $181,000, net of tax. See Note 8.
+Natural Gas Imbalances 
+The Company follows the entitlement method of accounting for its proportionate share of gas
+production on a well-by-well basis, recording a receivable to the extent that a well is in an
+“undertake” position and conversely recording a liability to the extent that a well is in an
+“overtake” position. Gas balancing receivables were
+$725,000 and $1.1 million as of December 31, 2004 and 2003,
+respectively. Gas balancing payables were $594,000 and $193,000 as of
+December 31, 2004 and 2003, respectively.
+Derivatives 
+The Company uses derivative financial instruments for price protection purposes on a limited amount
+of its future production and does not use them for trading purposes. Such derivatives are
+accounted for under SFAS 133. See Note 6
+Income Tax 
+The Company follows the asset and liability method of accounting for deferred income taxes
+prescribed by Statement of Financial Accounting Standards No. 109 (“SFAS 109”) “Accounting for
+Income Taxes”. The statement provides for the recognition of a deferred tax asset for deductible
+temporary timing differences, capital and operating loss carryforwards, statutory depletion
+carryforward and tax credit carryforwards, net of a “valuation allowance”. The valuation allowance
+is provided for that portion of the asset, for which it is deemed more likely than not, that it
+will not be realized. See Note 3.
+Accounts Receivable 
+Accounts receivable consists primarily of accrued oil and gas production receivables. The balance
+in the reserve for doubtful accounts included in accounts receivable was $103,000 at December 31,
+2004 and 2003. Net charge offs recorded against the reserve for doubtful accounts were $40,000 in
+2003. There were no provisions to expense in the three-year period ended December 31, 2004.
+52
+Table of Contents 
+Accounts Payable and Accrued Liabilities to be Refinanced 
+Amounts included in the Consolidated Balance Sheet represent capital expenditures in accounts
+payable and accrued liabilities that were refinanced with the availability under the Company’s
+senior secured credit facility subsequent to a specific Balance Sheet date. As of December 31,
+2004, there were no capital expenditures to be refinanced in the following month. Amounts in 2003
+were classified as short term because of the maturity of the credit facility on June 30, 2004.
+Sale of Production Payment Interest 
+In June 1999, the Company acquired a working interest in the Mobile Block 864 Area where the
+Company already owned an interest. Concurrent with this acquisition, the seller received a
+volumetric production payment, valued at approximately $14.8 million, from production attributable
+to a portion of the Company’s interest in the area over a 39-month period. The Company recorded
+deferred
+revenue associated with the sale of this production payment interest because a substantial
+obligation for future performance existed. Under the terms of the sale, the Company was obligated
+to deliver the production volumes free and clear of royalties, lease operating expenses, production
+taxes and all capital costs. The production payment was amortized, beginning in June 1999, to oil
+and gas sales on the units-of-production method as associated hydrocarbons were delivered, and
+expired in July 2002.
+Stock-Based Compensation 
+The Company’s pro forma net income (loss) and net income (loss) per share of common stock for the
+12-month periods ended December 31, 2004, 2003 and 2002 had compensation costs been recorded using
+the fair value method in accordance with SFAS 123, as amended by SFAS 148, are presented below
+pursuant to the disclosure requirements of SFAS 148 (in thousands except per share data):
+2004 
+2003 
+2002 
+(In thousands, except per share data) 
+Net income (loss) available to common shares,
+as reported 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+$ 
+(2,948 
+) 
+Stock-based compensation expense included
+in net income as reported, net of tax 
+348 
+17 
+270 
+Deduct: Total stock-based
+compensation expense under fair
+value based method, net of tax 
+(549 
+) 
+(247 
+) 
+(907 
+) 
+Pro forma net income (loss) available to
+common shares 
+$ 
+20,028 
+$ 
+(19,498 
+) 
+$ 
+(3,585 
+) 
+Basic
+earnings (loss) per share: As Reported 
+1.28 
+(1.41 
+) 
+(.22 
+) 
+Pro Forma 
+1.27 
+(1.43 
+) 
+(.27 
+) 
+Diluted earnings (loss) per share: As Reported 
+1.22 
+(1.41 
+) 
+(.22 
+) 
+Pro Forma 
+1.20 
+(1.43 
+) 
+(.27 
+) 
+See Note 12 for descriptions and additional disclosures related to the plans.
+53
+Table of Contents 
+Major Customers 
+The Company’s production is sold generally on month-to-month contracts at prevailing prices.
+The following table identifies customers to whom it sold a significant percentage of its total oil
+and gas production during each of the 12-month periods ended:
+December 31, 
+2004 
+2003 
+2002 
+Petrocom Energy Group, Ltd. 
+— 
+4 
+% 
+4 
+% 
+Dynegy 
+— 
+5 
+% 
+7 
+% 
+Prior Energy Corporation 
+— 
+20 
+% 
+— 
+Reliant Energy Services 
+6 
+% 
+28 
+% 
+70 
+% 
+Louis Dreyfus Energy Services 
+23 
+% 
+27 
+% 
+— 
+Shell Trading Company 
+30 
+% 
+— 
+— 
+Plains Marketing, L.P. 
+13 
+% 
+— 
+— 
+Conoco Phillips Company 
+8 
+% 
+— 
+— 
+Chevron Texaco Natural Gas 
+6 
+% 
+— 
+— 
+Because alternative purchasers of oil and gas are readily available, the Company believes that the
+loss of any of these purchasers would not result in a material adverse effect on its ability to
+market future oil and gas production.
+Statements of Cash Flows 
+For purposes of the Consolidated Financial Statements, the Company considers all highly liquid
+investments purchased with an original maturity of three months or less to be cash equivalents.
+The Company paid no federal income taxes for the three years in the period ended December 31,
+2004. During the years ended December 31, 2004, 2003 and 2002, the Company made cash payments for
+interest of $23,197,000, $27,913,000 and $25,507,000, respectively.
+Per Share Amounts 
+Basic income or loss per common share was computed by dividing net income or loss by the
+weighted average number of shares of common stock outstanding during the year. Diluted income or
+loss per common share was determined on a weighted average basis using common shares issued and
+outstanding adjusted for the effect of stock options considered common stock equivalents computed
+using the treasury stock method and the effect of the convertible preferred stock (if dilutive).
+The conversion of the preferred stock was not included in the annual calculation for 2003 and 2002
+due to its antidilutive effect on diluted income or loss per common share. In addition, below are
+the shares relating to stock options, warrants and restricted stock that were not included in
+diluted shares for the twelve-month periods ended December 31, 2003 and 2002 due to the fact that
+the Company had a loss for these periods. The Company had net income for the period ended December
+31, 2004 and all such shares were included as described below.
+54
+Table of Contents 
+Twelve Months Ended December 31, 
+(in thousands) 
+2003 
+2002 
+Stock options 
+63 
+13 
+Warrants 
+424 
+372 
+Restricted Stock 
+248 
+122 
+A reconciliation of the basic and diluted per share computation is as follows (in thousands, except
+per share amounts):
+2004 
+2003 
+2002 
+(a) Net income (loss) available to common shares 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+$ 
+(2,948 
+) 
+Preferred dividends assuming conversion of
+preferred stock (if dilutive) 
+1,272 
+— 
+— 
+(b) Income (loss) available to common shares assuming conversion of preferred stock (if dilutive) 
+$ 
+21,501 
+$ 
+(19,268 
+) 
+$ 
+(2,948 
+) 
+(c) Weighted average shares outstanding 
+15,796 
+13,662 
+13,387 
+Dilutive impact of stock options 
+233 
+— 
+— 
+Dilutive impact of restricted stock 
+75 
+— 
+— 
+Dilutive impact of warrants 
+894 
+— 
+— 
+Convertible preferred stock (if dilutive) 
+680 
+— 
+— 
+(d) Total diluted shares 
+17,678 
+13,662 
+13,387 
+Stock options and warrants excluded due to the
+exercise price being greater than the stock price 
+89 
+2,297 
+2,250 
+Basic income (loss) per share (a ¸ c) 
+$ 
+1.28 
+$ 
+(1.41 
+) 
+$ 
+(.22 
+) 
+Diluted income (loss) per share (b ¸ d) 
+$ 
+1.22 
+$ 
+(1.41 
+) 
+$ 
+(.22 
+) 
+Fair Value of Financial Instruments 
+Fair value of cash, cash equivalents, accounts receivable, accounts payable, the capital lease and
+the senior secured credit facility approximates book value at December 31, 2004 and 2003. Fair
+value of long-term debt (specifically, the 9.75% Senior Notes) had an estimated fair value of 106%
+of face value at December 31, 2004. Fair value of long-term debt (specifically, the 10.125%, the
+10.25%, and the 11% Senior Subordinated Notes and the 12% loans) had an estimated fair value of
+100% of face value at December 31, 2003.
+55
+Table of Contents 
+3. INCOME TAXES 
+The Company has recorded a net deferred tax asset at December 31, 2004 and 2003 and a valuation
+allowance at December 31, 2003 as follows:
+December 31, 
+2004 
+2003 
+(In thousands) 
+Federal net operating loss carryforwards 
+$ 
+56,271 
+$ 
+61,805 
+Statutory depletion carryforward 
+4,124 
+4,255 
+Alternative minimum tax credit carryforward 
+326 
+— 
+Temporary differences: 
+Oil and gas properties 
+(66,200 
+) 
+(66,725 
+) 
+Pipeline and other facilities 
+— 
+— 
+Non-oil and gas property 
+(77 
+) 
+(16 
+) 
+Other 
+1,988 
+2,031 
+SFAS 143-Asset Retirement Obligations 
+11,544 
+10,563 
+Permanent differences: 
+Employee benefits 
+787 
+(428 
+) 
+Other 
+(101 
+) 
+17 
+Total tax asset 
+8,662 
+11,502 
+Valuation allowance 
+— 
+(11,502 
+) 
+Net tax asset 
+$ 
+8,662 
+$ 
+— 
+SFAS 109 provides for the weighing of positive and negative evidence in determining whether it is
+more likely than not that a deferred tax asset is recoverable. The Company incurred losses in 2002
+and 2003 and had losses on an aggregate basis for the three-year period ended December 31, 2003.
+Because of these cumulative losses the Company established a full valuation allowance of $11.5
+million as of December 31, 2003.
+As a result of production from the Company’s first two deepwater projects starting in November
+2003, as well as refinancing its highest cost debt in 2004, the Company achieved profitable
+operations and has income on an aggregate basis for the three-year period ended December 31, 2004.
+Callon also expects 2005 production levels to exceed 2004 levels and expects to utilize most if not
+all of the deferred tax asset in 2005. As a result, the Company reversed the valuation allowance
+which had a balance of $7.0 million as of December 31, 2004.
+56
+Table of Contents 
+Below is a reconciliation of the reported amount of income tax expense attributable to continuing
+operations for the year to the amount of income tax expense that would result from applying
+domestic federal statutory tax rates to pretax income from continuing operations.
+Year Ended December 31, 
+2004 
+2003 
+2002 
+Income tax expense (benefit) computed at the statutory
+federal income tax rate 
+35 
+% 
+(35 
+%) 
+(35 
+%) 
+Change in valuation allowance 
+(84 
+%) 
+118 
+% 
+— 
+Write off of NOL’s 
+— 
+4 
+% 
+— 
+Effective income tax rate 
+(49 
+%) 
+87 
+% 
+(35 
+%) 
+If not utilized, the
+Company’s federal net operating loss carryforwards will expire in 2013
+through 2018.
+The Company has significant state net operating loss carryforwards that are not included in the
+deferred tax asset above, as the Company does not anticipate generating taxable state income in the
+states in which these loss carryforwards apply. The Company has very limited state taxable income
+as primarily all of its revenue is generated in federal waters not subject to state income taxes.
+4. OTHER COMPREHENSIVE INCOME 
+A recap of the Company’s 2004, 2003 and 2002 other comprehensive income (net of tax
+of $1.0 million, $242,000, and $3.5 million, respectively) is shown below
+(in thousands):
+Years Ended December 31, 
+2004 
+2003 
+2002 
+Other comprehensive income (loss): 
+Change in fair value of derivatives 
+$ 
+(1,863 
+) 
+$ 
+449 
+$ 
+(469 
+) 
+Amortization of Enron derivatives 
+— 
+— 
+(5,971 
+) 
+Total other comprehensive income (loss) 
+$ 
+(1,863 
+) 
+$ 
+449 
+$ 
+(6,440 
+) 
+57
+Table of Contents 
+5. LONG-TERM DEBT 
+Long-term debt consisted of the following at:
+December 31, 
+2004 
+2003 
+(In thousands) 
+Senior Secured Credit Facility 
+$ 
+5,000 
+$ 
+30,000 
+Senior Subordinated Notes (due 2004) – these
+notes were retired with restricted cash on
+01/08/2004: 
+10.125% notes net of discount 
+— 
+21,772 
+* 
+10.250% notes 
+— 
+40,000 
+* 
+12% Senior Loans (due 2005) net of discount 
+— 
+9,490 
+11% Senior Subordinated Notes (due 2005) 
+— 
+33,000 
+9.75% Senior Notes (due 2010) net of discount 
+186,216 
+170,684 
+Capital Lease 
+1,711 
+3,162 
+Total Long-term Debt 
+192,927 
+308,108 
+Less current portion 
+576 
+93,223 
+* 
+Long-term portion 
+$ 
+192,351 
+$ 
+214,885 
+* 
+$62.9 million of 2004 senior subordinated notes are in this current portion and were
+retired on January 8, 2004. 
+Senior Secured Credit Facility . On June 15, 2004, the Company closed on a three-year senior secured
+credit facility underwritten by Union Bank of California, N.A. (“Union Bank”) to replace the
+Company’s credit facility with Wachovia Bank, National Association (“Wachovia Bank”) which was
+expiring June 30, 2004. The credit facility includes an initial borrowing base of $60 million,
+which may be adjusted semi-annually and can be increased to a maximum of $175 million. Borrowings
+under the credit facility are secured by mortgages covering the Company’s five largest fields. The
+credit facility bears interest at 0.25% above a defined base rate depending on utilization of the
+borrowing base or, at the option of the Company, LIBOR plus 1.5% to 2.25% based on utilization of
+the borrowing base. Under the senior secured credit facility, a commitment fee of 0.25% or 0.375%
+per annum, depending on the amount of the unused portion of the borrowing base, is payable
+quarterly.
+The range of interest rates on the senior secured credit facilities for both Union Bank and
+Wachovia Bank combined were 3.09% to 5.50% for the 12 months ended December 31, 2004. The weighted
+average interest rate for the senior secured credit facilities debt outstanding at December 31,
+2004 and 2003 was 4.16% and 15%, respectively.
+As of December 31, 2004 there was $5.0 million outstanding under the facility and Callon had an
+aggregate of $2.3 million in outstanding letters of credit issued under the credit facility. These
+letters of credit secure obligations under the outstanding hedging contracts described in Note 6 to
+the Consolidated Financial Statements. The outstanding letters of credit reduce the amount
+available for borrowings under the credit facility. As a result, $52.7 million was available for
+future borrowings under the credit facility as of December 31, 2004.
+58
+Table of Contents 
+Restructured Debt . In December 2003 and in the first half of 2004, the Company completed several
+transactions which restructured all debt that was maturing through 2005. The transactions were
+• 
+borrowing $185 million pursuant to a senior unsecured credit facility for a term of
+seven years at an interest rate of 9.75% in December 2003; 
+• 
+the formation of Medusa Spar LLC in which the Company contributed its 15% ownership in
+the deepwater spar production facilities in return for a 10% interest in Medusa Spar LLC
+and approximately $25 million in cash; 
+• 
+borrowing an additional $15 million for a term of seven years at an interest rate of
+9.75% pursuant to a senior unsecured credit agreement in the first quarter of 2004; 
+• 
+closing a three-year senior secured credit facility with an initial borrowing base of
+$60 million in June 2004 which can be increased by the lender to $175 million; and 
+• 
+closing the public offering of 3,450,000 shares of common stock priced at $13.25 per
+share raising net proceeds of approximately $44 million, after expenses, in June 2004. 
+Below is a list of the debt which was extinguished and restructured with the funds raised from the
+transactions above.
+• 
+the Company’s $22.9 million, 10.125% senior subordinated notes due in 2004 
+• 
+the Company’s $40 million, 10.25% senior subordinated notes due in 2004 
+• 
+the Company’s $95 million, 12% senior unsecured credit facility due in 2005 
+• 
+the Company’s $33 million, 11% senior subordinated notes due in 2005 
+All of the above debt was extinguished before maturity which resulted in a loss on early
+extinguishment of debt for the twelve-month periods ended December 31, 2004 and 2003 of $3.0
+million and $5.6 million, respectively. In addition to restructuring the Company’s debt, Callon
+reduced the balance outstanding on its senior secured credit facility.
+9.75% Senior Notes (due 2010). In December 2003 the Company borrowed $185 million pursuant to
+a senior unsecured credit facility. The loans under the credit facility have a stated interest
+rate of 9.75% and a seven-year maturity. The net proceeds of $181.3 million were used to redeem
+$22.9 million of 10.125% senior subordinated notes due July 31, 2004, $40 million of 10.25% senior
+subordinated notes due September 15, 2004 and $85 million
+of our 12% loan due March 31, 2005 issued pursuant to a senior unsecured credit agreement dated
+July 29, 2001 plus a 1% pre-payment premium of $850,000, and to reduce the balance outstanding
+under the Company’s senior secured credit facility. In conjunction with the new senior unsecured
+notes, the Company issued detachable warrants to purchase 2.775 million shares of it’s common stock
+at an exercise price of $10 per share and an expiration date in
+December 2010. The warrants were valued at $10.6 million and were treated
+as a discount on the debt. This senior unsecured debt matures December 8, 2010 and has an
+effective interest rate of 11.4%. The Company recorded the issuance of these new securities at a
+fair value of $171 million. Deferred costs of $14 million associated with the notes will be
+amortized over the life of the notes.
+During March 2004, Callon borrowed an additional $15 million under its 9.75% senior unsecured
+credit facility bringing the total outstanding under the facility to $200 million. The net proceeds
+of approximately $14 million were primarily used to retire the remaining $10 million of 12% senior
+loans due March 31, 2005 plus a 1% call premium of $100,000. The Company recorded the issuance of
+these additional new securities at a fair value of $14 million. Deferred costs of $1 million
+associated with the notes will be amortized over the life of the notes.
+59
+Table of Contents 
+In March 2004, the $200 million in aggregate principal amount of loans outstanding under the
+9.75% senior unsecured credit facility were exchanged for 9.75% Senior Notes due 2010, Series A,
+“Series A notes”, issued pursuant to a senior indenture between Callon and American Stock Transfer
+& Trust Company dated March 15, 2004. On August 12, 2004, the Company completed an offer to
+exchange its 9.75% Senior Notes due 2010, Series B, that have been registered under the Securities
+Act of 1933, for all outstanding Series A notes.
+Capital Lease . In December 2001, the Company entered into a 10-year gas processing agreement
+associated with a production facility on Callon’s Mobile Block 952 Field with Hanover Compression
+Limited Partnership, which is being accounted for as a capital lease. Total minimum obligations
+are $8.4 million with interest representing approximately $2.8 million and the present value
+minimum obligations representing $5.6 million.
+Restrictive Covenants . The senior secured credit facility and the senior notes contain various
+covenants including restrictions on additional indebtedness and payment of cash dividends as well
+as maintenance of certain financial ratios. The Company was in compliance with these covenants at
+December 31, 2004.
+Future minimum lease payments and debt maturities (in thousands) are as follows: 
+Capital Lease 
+Year 
+Payments 
+Debt 
+2005 
+$ 
+822 
+$ 
+— 
+2006 
+439 
+— 
+2007 
+348 
+5,000 
+2008 
+228 
+— 
+2009 
+229 
+— 
+Thereafter 
+465 
+200,000 
+60
+Table of Contents 
+6. DERIVATIVES 
+The Company periodically uses derivative financial instruments to manage oil and gas price risk.
+Settlements on commodity price contracts are generally based upon the difference between the
+contract price or prices specified in the derivative instrument and a NYMEX price or other cash or
+futures index price.
+The Company’s derivative contracts that are accounted for as cash flow hedges under SFAS 133 are
+recorded at fair market value and the changes in fair value are recorded through other
+comprehensive income (loss), net of tax, in stockholders’ equity. The cash settlements on these
+contracts are recorded as an increase or decrease in oil and gas sales. Cash settlements on the
+derivative contracts for the twelve-month periods ended December 31, 2004 and 2003 resulted in a
+reduction of oil and gas sales in the amount of $13.8 million and $2.9 million, respectively, and
+an increase in oil and gas sales of $9.2 million for the twelve-month period ended December 31,
+2002.
+The changes in fair value of the Company’s derivative contracts that are not designated as
+effective cash flow hedges are recorded through the statement of operations as derivative expense.
+In addition, the change in fair value relating to the ineffective portion of cash flow hedges is
+recorded as derivative expense. The following table summarizes derivative expense for the periods
+presented (in thousands):
+December 31, 
+2004 
+2003 
+2002 
+Ineffective portion of hedges qualifying for hedge
+accounting included in derivative expense 
+$ 
+(1,209 
+) 
+$ 
+— 
+$ 
+— 
+Non-designated derivative contracts included in
+derivative expense 
+(162 
+) 
+(535 
+) 
+(708 
+) 
+$ 
+(1,371 
+) 
+$ 
+(535 
+) 
+$ 
+(708 
+) 
+61
+Table of Contents 
+The fair value of all the oil and a portion of the gas derivative contracts at December 31, 2004
+was a current liability of $2,993,000. The fair value of the remaining portion of the gas
+derivative contracts was a current asset of $1,570,000.
+Listed in the table below are the outstanding derivative contracts as of December 31,
+2004:
+Swaps
+Volumes per 
+Quantity 
+Average 
+Product 
+Month 
+Type 
+Price 
+Period 
+Oil 
+30,000 
+Bbls 
+$ 
+31.29 
+01/05 
+Oil 
+15,000 
+Bbls 
+$ 
+30.00 
+01/05-03/05 
+Puts
+Volumes per 
+Quantity 
+Average 
+Product 
+Month 
+Type 
+Price 
+Period 
+Oil 
+50,000 
+Bbls 
+$ 
+35.00 
+02/05-06/05 
+Oil 
+7,000 
+Bbls 
+$ 
+35.00 
+01/05-12/05 
+Natural Gas 
+270,000 
+MMBtu 
+$ 
+5.00 
+04/05-10/05 
+Natural Gas 
+120,000 
+MMBtu 
+$ 
+5.00 
+01/05-10/05 
+Natural Gas 
+100,000 
+MMBtu 
+$ 
+5.00 
+04/05-12/05 
+Natural Gas 
+300,000 
+MMBtu 
+$ 
+6.50 
+01/05-03/05 
+Collars
+Average 
+Average 
+Volumes per 
+Quantity 
+Floor 
+Ceiling 
+Product 
+Month 
+Type 
+Price 
+Price 
+Period 
+Oil 
+45,000 
+Bbls 
+$ 
+29.33 
+$ 
+32.17 
+01/05 
+Oil 
+15,000 
+Bbls 
+$ 
+32.50 
+$ 
+40.00 
+01/05-12/05 
+Oil 
+15,208 
+Bbls 
+$ 
+40.00 
+$ 
+50.00 
+01/05-12/05 
+Oil 
+15,000 
+Bbls 
+$ 
+32.50 
+$ 
+40.00 
+02/05-12/05 
+Oil 
+15,000 
+Bbls 
+$ 
+35.00 
+$ 
+43.50 
+03/05-12/05 
+Natural Gas 
+300,000 
+MMBtu 
+$ 
+5.00 
+$ 
+6.91 
+01/05-03/05 
+Natural Gas 
+190,000 
+MMBtu 
+$ 
+5.00 
+$ 
+12.80 
+01/05-03/05 
+Natural Gas 
+100,000 
+MMBtu 
+$ 
+5.00 
+$ 
+7.75 
+04/05-10/05 
+Natural Gas 
+200,000 
+MMBtu 
+$ 
+5.75 
+$ 
+7.75 
+04/05-10/05 
+7. COMMITMENTS AND CONTINGENCIES 
+As described in Note 11, abandonment trusts (the “Trusts”) have been established for future
+abandonment obligations of those oil and gas properties of the Company burdened by a net profits
+interest. The management of the Company believes the Trusts will be sufficient to offset those
+future abandonment liabilities; however, the Company is responsible for any abandonment expenses in
+excess of the Trusts’ balances. As of December 31, 2004, total estimated site restoration,
+dismantlement and abandonment costs were approximately $7.8 million, net of expected salvage value.
+Substantially all such costs are expected to be funded through the Trusts’ funds, all of which
+will be accessible to the Company when abandonment work begins. In addition, as a working interest
+owner and/or operator of oil and gas properties, the Company is responsible for the cost of
+abandonment of such properties. See Notes 2 and 8.
+62
+Table of Contents 
+From time to time, the Company, as part of the Consolidation and other capital transactions,
+entered into registration rights agreements whereby certain parties to the transactions are
+entitled to require the Company to register common stock of the Company owned by them with the
+Securities and Exchange Commission for sale to the public in firm commitment public offerings and
+generally to include shares owned by them, at no cost, in registration statements filed by the
+Company. Costs of the offering will not include broker’s discounts and commissions, which will be
+paid by the respective sellers of the common stock.
+The Company is involved in various claims and lawsuits incidental to its business. In the opinion
+of management, the ultimate liability thereunder, if any, will not have a material adverse effect
+on the financial position or results of operations of the Company.
+The Company’s Medusa deepwater property is eligible for royalty suspensions pursuant to the Deep
+Water Royalty Relief Act. However, the federal offshore leases covering this property contains
+“price threshold” provisions for oil and gas prices. Under these “price threshold” provisions, if
+the average monthly New York Mercantile Exchange (NYMEX) sales price for oil or gas during a fiscal
+year exceeds the price threshold for oil or gas, respectively, then royalties on the associated
+production must be paid to the Minerals Management Service (MMS) at the rate stipulated in the
+lease. The price thresholds are adjusted annually by the implicit price deflator for the GDP. The
+determination of whether or not royalties are due as a result of the average NYMEX price exceeding
+the price threshold is made during the first quarter of the succeeding year. Any royalty payments
+due must be made shortly after this determination is made. If a royalty payment is due for all
+production during a year as a result of exceeding the price threshold, the lessee is required to
+make monthly royalty payments during the succeeding fiscal year for the succeeding year’s
+production. If at the end of any year the average NYMEX price is below the price threshold, the
+lessee can apply for a refund for any associated royalties paid during that year and the lessee
+will not be required to pay royalties monthly during the succeeding year for the succeeding year’s
+production.
+The thresholds and the average NYMEX prices are calculated by the MMS. The average NYMEX price for
+2004 was $41.38 per barrel of oil and $6.18 per MMBtu of natural gas. For the year ended December
+31, 2004 the thresholds were $34.23 per barrel of oil
+and $4.28 per MMBtu of natural gas, subject to finalization of the adjustment for the 2004 GDP
+implicit price deflator. The Company was required to make monthly royalty payments for 2004 gas
+production. The Company accrued payments for 2004 oil royalties and will be required to pay these
+royalties to the MMS in the first quarter of 2005 after finalization of the price threshold. The
+Company will be required to make monthly royalty payments for both oil and gas production for 2005.
+In the year succeeding the year in which any of the Company’s properties became subject to
+royalties as the result of the average NYMEX price exceeding the price threshold, the portion of
+reserves attributable to potential future royalties would not be included in a year-end reserve
+report. However, if the average NYMEX prices were below the price thresholds in subsequent years,
+our reserves would be increased to reflect reserves previously attributed to future royalties. As
+a result, reported oil and gas reserves could materially increase or decrease, depending on the
+relation of price thresholds versus the average NYMEX prices. The reduction in revenues resulting
+from an obligation to pay these royalties and subsequent reduction of proved reserves could have a
+material adverse effect on the Company’s results of operations and financial condition. The
+Company’s reserve report as of December 31, 2004 excluded oil and gas reserves for Medusa that are
+subject to MMS royalties as a result of the average 2004 NYMEX prices for oil and gas exceeding the
+price thresholds.
+63
+Table of Contents 
+The Company’s activities are subject to federal, state and local laws and regulations governing
+environmental quality and pollution control. Although no assurances can be made, the Company
+believes that, absent the occurrence of an extraordinary event, compliance with existing federal,
+state and local laws, rules and regulating the release of materials in the environment or otherwise
+relating to the protection of the environment will not have a material effect upon the capital
+expenditures, earnings or the competitive position of the Company with respect to its existing
+assets and operations. The Company cannot predict what effect additional regulation or
+legislation, enforcement polices thereunder, and claims for damages to property, employees, other
+persons and the environment resulting from the Company’s operations could have on its activities.
+8. ASSET RETIREMENT OBLIGATIONS 
+As discussed in Note 2, the Company adopted SFAS 143 on January 1, 2003. The impact of adopting
+the statement resulted in a gain of $181,000, net of tax, which was reported as a cumulative effect
+of change in accounting principle.
+Approximately $30.3 million was recorded as the present value of asset retirement obligations
+on January 1, 2003 with the adoption of SFAS 143 related to the Company’s oil and gas properties.
+Interest is accreted on this amount and reported as accretion expense in the Consolidated
+Statements of Operations.
+Assets, primarily short-term U.S. Government securities, of approximately $7.7 million at December
+31, 2004, of which $2.1 million is current, are recorded as restricted investments. These assets
+are held in abandonment trusts dedicated to pay future abandonment costs of oil and gas properties
+in which the Company has sold a net profits interest. If there is any excess of trust assets over
+abandonment costs, the excess will be distributed to the net profits interest owners.
+The following table summarizes the activity for the Company’s asset retirement obligation:
+Twelve Months Ended 
+December 31, 2004 
+December 31, 2003 
+Asset retirement obligation at beginning of period 
+$ 
+33,691 
+$ 
+— 
+Liability recognized upon adoption 
+— 
+30,251 
+Accretion expense 
+3,400 
+2,884 
+Net profits interest accretion 
+459 
+371 
+Liabilities incurred 
+3,065 
+3,649 
+Liabilities settled 
+(2,076 
+) 
+(2,847 
+) 
+Revisions to estimate 
+(257 
+) 
+(617 
+) 
+Asset retirement obligation at end of period 
+38,282 
+33,691 
+Less: current retirement obligation 
+(13,300 
+) 
+(8,571 
+) 
+Long-term retirement obligation 
+$ 
+24,982 
+$ 
+25,120 
+Pro forma net income and earnings per share are not presented for the 12 months ended December 31,
+2002 because the pro forma application of SFAS 143 to the prior periods would not result in pro
+forma net income and earnings per share materially different from the actual amounts reported for
+the periods in the accompanying Consolidated Statements of Operations.
+64
+Table of Contents 
+9. OIL AND GAS PROPERTIES 
+The following table discloses certain financial data relating to the Company’s oil and gas
+activities, all of which are located in the United States.
+Years Ended December 31, 
+2004 
+2003 
+2002 
+(In thousands) 
+Capitalized costs incurred: 
+Evaluated Properties-
+Beginning of period balance 
+$ 
+802,912 
+$ 
+762,918 
+$ 
+704,937 
+Property acquisition costs 
+1,355 
+1,154 
+1,471 
+Exploration costs 
+26,749 
+21,390 
+17,851 
+Development costs 
+32,004 
+33,972 
+43,151 
+SFAS 143-Asset Retirement Obligation 
+(918 
+) 
+18,002 
+— 
+Medusa Spar transaction 
+— 
+(33,542 
+) 
+— 
+Sale of mineral interests 
+(1 
+) 
+(982 
+) 
+(4,492 
+) 
+End of period balance 
+$ 
+862,101 
+$ 
+802,912 
+$ 
+762,918 
+Unevaluated Properties (excluded from
+amortization) -
+Beginning of period balance 
+$ 
+34,251 
+$ 
+40,997 
+$ 
+37,560 
+Additions 
+16,367 
+5,228 
+5,802 
+Capitalized interest 
+4,577 
+4,862 
+5,289 
+Transfers to evaluated 
+(16,153 
+) 
+(16,836 
+) 
+(7,654 
+) 
+End of period balance 
+$ 
+39,042 
+$ 
+34,251 
+$ 
+40,997 
+Accumulated depreciation, depletion
+and amortization-
+Beginning of period balance 
+$ 
+447,000 
+$ 
+426,254 
+$ 
+399,339 
+Provision charged to expense 
+47,453 
+28,195 
+26,915 
+Cumulative effect of change in accounting
+Principle 
+— 
+(7,449 
+) 
+— 
+End of period balance 
+$ 
+494,453 
+$ 
+447,000 
+$ 
+426,254 
+Unevaluated property costs, primarily lease acquisition costs incurred at federal and state
+lease sales, unevaluated drilling costs, capitalized interest and general and administrative costs
+being excluded from the amortizable evaluated property base, consisted of $10.2 million incurred in
+2004, $7.5 million incurred in 2003 and $21.3 million incurred in 2002 and prior. These costs are
+directly related to the acquisition and evaluation of unproved properties and major development
+projects. The excluded costs and related reserves are included in the amortization base as the
+properties are evaluated and proved reserves are established or impairment is determined. The
+Company expects that the majority of these costs will be evaluated over the next three to five-year
+period.
+Depletion per unit-of-production (thousand cubic feet of gas equivalent) amounted to $2.18, $2.03
+and $1.73 for the years ended December 31, 2004, 2003, and 2002, respectively.
+Under the full-cost accounting rules of the SEC, the Company reviews the carrying value of its
+proved oil and gas properties each quarter. Under these rules, capitalized costs of proved oil and
+gas properties net of accumulated depreciation, depletion and amortization (DD&A) and deferred
+income taxes, may not exceed the present value of estimated future net cash flows from proved oil
+and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved
+properties included in the costs being amortized, net of related tax effects. These rules
+generally require pricing future oil and gas production at the unescalated market price for oil and
+gas at the end of each fiscal quarter and require a write-down if the “ceiling” is exceeded, unless
+prices recover sufficiently before the date of the auditor’s report. Given the volatility of oil
+and gas prices, it is reasonably possible that the Company’s estimate of discounted future net cash
+flows from proved oil and gas reserves could change in the near term. If oil and gas prices
+decline significantly, even if only for a short period of time, it is possible that writedowns of
+oil and gas properties could occur in the future.
+65
+Table of Contents 
+of related tax effects. These rules generally require pricing future oil and gas production
+at the unescalated market price for oil and gas at the end of each fiscal quarter and require a
+write-down if the “ceiling” is exceeded, unless prices recover sufficiently before the date of the
+auditor’s report. Given the volatility of oil and gas prices, it is reasonably possible that the
+Company’s estimate of discounted future net cash flows from proved oil and gas reserves could
+change in the near term. If oil and gas prices decline significantly, even if only for a short
+period of time, it is possible that writedowns of oil and gas properties could occur in the future.
+10. CONSOLIDATING CONDENSED FINANCIAL INFORMATION 
+Certain of the Company’s subsidiaries have fully and unconditionally guaranteed the payment of all
+obligations under the Company’s $200 million 9.75% Senior Notes due 2010 and the $175 million
+senior secured credit facility. The following tables present the consolidating condensed financial
+information of Callon Petroleum Company, as the parent company, and guarantor subsidiaries of
+Callon Petroleum Company balance sheets as of December 31, 2004 and December 31, 2003, and
+statements of income and cash flows for the twelve-month periods ended December 31, 2004, December
+31, 2003 and December 31, 2002.
+Callon Petroleum Company 
+Consolidating Condensed Guarantor Subsidiaries and Parent Company 
+Financial Information As of December 31, 2004 and December 31, 2003 
+And For The Twelve-Month Periods Ended 
+December 31, 2004, December 31, 2003 and December 31, 2002 
+Unaudited 
+(In thousands) 
+Callon Petroleum 
+Consolidating 
+Company 
+and 
+Callon Petroleum 
+(Parent 
+Guarantor 
+Eliminating 
+Company 
+Obligor) 
+Subsidiaries 
+Entries 
+Consolidated 
+As of December 31, 2004 
+Balance Sheet 
+Current assets 
+$ 
+728 
+$ 
+27,348 
+$ 
+— 
+$ 
+28,076 
+Intercompany receivables 
+297,480 
+— 
+(297,480 
+) 
+— 
+Investment in subsidiaries 
+90,253 
+1,903 
+(92,156 
+) 
+— 
+Oil and gas properties 
+1,463 
+405,227 
+— 
+406,690 
+Other assets 
+2,357 
+20,400 
+— 
+22,757 
+Total assets 
+$ 
+392,281 
+$ 
+454,878 
+$ 
+(389,636 
+) 
+$ 
+457,523 
+Current liabilities 
+$ 
+634 
+$ 
+40,482 
+— 
+41,116 
+Intercompany payables 
+— 
+297,480 
+(297,480 
+) 
+— 
+Long-term debt, less
+current maturities 
+191,216 
+1,135 
+— 
+192,351 
+Other accrued liabilities 
+236 
+25,508 
+— 
+25,744 
+Stockholders’ equity 
+200,195 
+90,273 
+(92,156 
+) 
+198,312 
+Total liabilities and
+stockholders’ equity 
+$ 
+392,281 
+$ 
+454,878 
+$ 
+(389,636 
+) 
+$ 
+457,523 
+66
+Table of Contents 
+Callon Petroleum 
+Consolidating 
+Company 
+and 
+Callon Petroleum 
+(Parent 
+Guarantor 
+Eliminating 
+Company 
+Obligor) 
+Subsidiaries 
+Entries 
+Consolidated 
+As of December 31, 2003 
+Balance Sheet 
+Current assets 
+$ 
+64,300 
+$ 
+21,468 
+$ 
+— 
+$ 
+85,768 
+Intercompany receivables 
+317,394 
+— 
+(317,394 
+) 
+— 
+Investment in subsidiaries 
+54,247 
+2,039 
+(56,286 
+) 
+— 
+Oil and gas properties 
+3,129 
+387,034 
+— 
+390,163 
+Other assets 
+1,557 
+18,544 
+— 
+20,101 
+Total assets 
+$ 
+440,627 
+$ 
+429,085 
+$ 
+(373,680 
+) 
+$ 
+496,032 
+Current liabilities 
+$ 
+93,846 
+$ 
+26,751 
+$ 
+— 
+$ 
+120,597 
+Intercompany payables 
+— 
+317,394 
+(317,394 
+) 
+— 
+Long-term debt, less current maturities 
+213,173 
+1,712 
+— 
+214,885 
+Other accrued liabilities 
+327 
+26,962 
+— 
+27,289 
+Stockholders’ equity 
+133,281 
+56,266 
+(56,286 
+) 
+133,261 
+Total liabilities and
+stockholders’ equity 
+$ 
+440,627 
+$ 
+429,085 
+$ 
+(373,680 
+) 
+$ 
+496,032 
+67
+Table of Contents 
+Callon Petroleum 
+Consolidating 
+Company 
+and 
+Callon Petroleum 
+(Parent 
+Guarantor 
+Eliminating 
+Company 
+Obligor) 
+Subsidiaries 
+Entries 
+Consolidated 
+For The Twelve Months Ended December 31, 2004 
+Statement of Income 
+Operating revenues: 
+Oil and gas sales 
+$ 
+4,614 
+$ 
+115,188 
+$ 
+— 
+$ 
+119,802 
+Total operating revenues 
+4,614 
+115,188 
+— 
+119,802 
+Operating expenses: 
+Lease operating expenses 
+472 
+21,836 
+— 
+22,308 
+Depreciation, depletion and
+amortization 
+1,772 
+45,681 
+— 
+47,453 
+General and administrative 
+1,652 
+7,106 
+— 
+8,758 
+Accretion expense 
+13 
+3,387 
+— 
+3,400 
+Derivative expense 
+— 
+1,371 
+— 
+1,371 
+Total operating expenses 
+3,909 
+79,381 
+— 
+83,290 
+Income from operations 
+705 
+35,807 
+— 
+36,512 
+Other (income) expenses: 
+Interest expense 
+403 
+19,734 
+— 
+20,137 
+Other income 
+(252 
+) 
+(105 
+) 
+— 
+(357 
+) 
+Loss on early extinguishment of
+debt 
+60 
+2,944 
+— 
+3,004 
+Equity in earnings of subsidiaries 
+(21,007 
+) 
+— 
+21,007 
+— 
+Total other (income) expenses 
+(20,796 
+) 
+22,573 
+21,007 
+22,784 
+Income (loss) before income taxes 
+21,501 
+13,234 
+(21,007 
+) 
+13,728 
+Income tax expense (benefit) 
+— 
+(6,697 
+) 
+— 
+(6,697 
+) 
+Income (loss) before Medusa Spar
+LLC 
+21,501 
+19,931 
+(21,007 
+) 
+20,425 
+Income from Medusa Spar LLC, net
+of tax 
+— 
+1,076 
+— 
+1,076 
+Net Income (loss) 
+21,501 
+21,007 
+(21,007 
+) 
+21,501 
+Preferred stock dividends 
+1,272 
+— 
+— 
+1,272 
+Net income 
+$ 
+20,229 
+$ 
+21,007 
+$ 
+(21,007 
+) 
+$ 
+20,229 
+68
+Table of Contents 
+Callon Petroleum 
+Consolidating 
+Company 
+and 
+Callon Petroleum 
+(Parent 
+Guarantor 
+Eliminating 
+Company 
+Obligor) 
+Subsidiaries 
+Entries 
+Consolidated 
+For The Twelve Months Ended December 31, 2003 
+Statement of Income 
+Operating revenues: 
+Oil and gas sales 
+$ 
+4,108 
+$ 
+69,589 
+$ 
+— 
+$ 
+73,697 
+Total operating revenues 
+4,108 
+69,589 
+— 
+73,697 
+Operating expenses: 
+Lease operating expenses 
+452 
+10,849 
+— 
+11,301 
+Depreciation, depletion and amortization 
+1,624 
+26,629 
+— 
+28,253 
+General and administrative 
+1,260 
+3,453 
+— 
+4,713 
+Accretion expense 
+20 
+2,864 
+— 
+2,884 
+Derivative expense 
+— 
+535 
+— 
+535 
+Total operating expenses 
+3,356 
+44,330 
+— 
+47,686 
+Income from operations 
+752 
+25,259 
+— 
+26,011 
+Other (income) expenses: 
+Interest expense 
+704 
+29,910 
+— 
+30,614 
+Other income 
+(199 
+) 
+(245 
+) 
+— 
+(444 
+) 
+Loss on early extinguishment of debt 
+128 
+5,445 
+— 
+5,573 
+Equity in earnings of subsidiaries 
+20,697 
+— 
+(20,697 
+) 
+— 
+Total other (income) expenses 
+21,330 
+35,110 
+(20,697 
+) 
+35,743 
+Income (loss) before income taxes 
+(20,578 
+) 
+(9,851 
+) 
+20,697 
+(9,732 
+) 
+Income tax expense (benefit) 
+(2,553 
+) 
+10,985 
+— 
+8,432 
+Income (loss) before Medusa Spar LLC
+and cumulative effect of change in
+accounting principle 
+(18,025 
+) 
+(20,836 
+) 
+20,697 
+(18,164 
+) 
+Loss from Medusa Spar LLC, net of tax 
+— 
+(8 
+) 
+— 
+(8 
+) 
+Income (loss) before cumulative effect
+of change in accounting principle 
+(18,025 
+) 
+(20,844 
+) 
+(20,697 
+) 
+(18,172 
+) 
+Cumulative effect of change in
+accounting principle, net of tax 
+34 
+147 
+— 
+181 
+Net Income (loss) 
+(17,991 
+) 
+(20,697 
+) 
+20,697 
+(17,991 
+) 
+Preferred stock dividends 
+1,277 
+— 
+— 
+1,277 
+Net income 
+$ 
+(19,268 
+) 
+$ 
+(20,697 
+) 
+$ 
+20,697 
+$ 
+(19,268 
+) 
+69
+Table of Contents 
+Callon Petroleum 
+Consolidating 
+Company 
+and 
+Callon Petroleum 
+(Parent 
+Guarantor 
+Eliminating 
+Company 
+Obligor) 
+Subsidiaries 
+Entries 
+Consolidated 
+For The Twelve Months Ended December 31, 2002 
+Statement of Income 
+Operating revenues: 
+Oil and gas sales 
+$ 
+3,064 
+$ 
+58,107 
+$ 
+— 
+$ 
+61,171 
+Total operating revenues 
+3,064 
+58,107 
+— 
+61,171 
+Operating expenses: 
+Lease operating expenses 
+1,273 
+9,757 
+— 
+11,030 
+Depreciation, depletion and amortization 
+1,579 
+25,517 
+— 
+27,096 
+General and administrative 
+1,163 
+3,542 
+— 
+4,705 
+Accretion expense 
+— 
+— 
+— 
+— 
+Derivative expense 
+— 
+708 
+— 
+708 
+Total operating expenses 
+4,015 
+39,524 
+— 
+43,539 
+Income from operations 
+(951 
+) 
+18,583 
+— 
+17,632 
+Other (income) expenses: 
+Interest expense 
+836 
+25,304 
+— 
+26,140 
+Other income 
+(1,623 
+) 
+(4,314 
+) 
+— 
+(5,937 
+) 
+Loss on early extinguishment of debt 
+— 
+— 
+— 
+— 
+Equity in earnings of subsidiaries 
+1,565 
+— 
+(1,565 
+) 
+— 
+Total other (income) expenses 
+778 
+20,990 
+(1,565 
+) 
+20,203 
+Income (loss) before income taxes 
+(1,729 
+) 
+(2,407 
+) 
+1,565 
+(2,571 
+) 
+Income tax expense (benefit) 
+(58 
+) 
+(842 
+) 
+— 
+(900 
+) 
+Income (loss) before cumulative effect
+of change in accounting principle 
+(1,671 
+) 
+(1,565 
+) 
+1,565 
+(1,671 
+) 
+Cumulative effect of change in
+accounting principle, net of tax 
+— 
+— 
+— 
+— 
+Net Income (loss) 
+(1,671 
+) 
+(1,565 
+) 
+1,565 
+(1,671 
+) 
+Preferred stock dividends 
+1,277 
+— 
+— 
+1,277 
+Net income 
+$ 
+(2,948 
+) 
+$ 
+(1,565 
+) 
+$ 
+1,565 
+$ 
+(2,948 
+) 
+70
+Table of Contents 
+Callon Petroleum 
+Consolidating 
+Company 
+and 
+Callon Petroleum 
+(Parent 
+Guarantor 
+Eliminating 
+Company 
+Obligor) 
+Subsidiaries 
+Entries 
+Consolidated 
+For The Twelve Months Ended December 31, 2004 
+Statement of Cash Flow 
+Net cash provided
+(used in) operating
+activities 
+$ 
+10,315 
+$ 
+60,593 
+$ 
+— 
+$ 
+70,908 
+Net cash provided by
+(used in) investing
+activities 
+(210 
+) 
+(64,100 
+) 
+— 
+(64,310 
+) 
+Net cash provided by
+(used in) financing
+activities 
+(10,580 
+) 
+(1,452 
+) 
+— 
+(12,032 
+) 
+Net increase
+(decrease) in cash
+and cash equivalents 
+(475 
+) 
+(4,959 
+) 
+— 
+(5,434 
+) 
+Cash and cash
+equivalents at
+beginning of the
+period 
+486 
+8,214 
+— 
+8,700 
+Cash and cash
+equivalents at end of
+the period 
+$ 
+11 
+$ 
+3,255 
+$ 
+— 
+$ 
+3,266 
+Callon Petroleum 
+Consolidating 
+Company 
+and 
+Callon Petroleum 
+(Parent 
+Guarantor 
+Eliminating 
+Company 
+Obligor) 
+Subsidiaries 
+Entries 
+Consolidated 
+For The Twelve Months Ended December 31, 2003 
+Statement of Cash Flow 
+Net cash provided
+(used in) operating
+activities 
+$ 
+3,547 
+$ 
+31,082 
+$ 
+— 
+$ 
+34,629 
+Net cash provided by
+(used in) investing
+activities 
+(12 
+) 
+(23,303 
+) 
+— 
+(23,315 
+) 
+Net cash provided by
+(used in) financing
+activities 
+(3,240 
+) 
+(5,181 
+) 
+— 
+(8,421 
+) 
+Net increase
+(decrease) in cash
+and cash equivalents 
+295 
+2,598 
+— 
+2,893 
+Cash and cash
+equivalents at
+beginning of the
+period 
+191 
+5,616 
+— 
+5,807 
+Cash and cash
+equivalents at end of
+the period 
+$ 
+486 
+$ 
+8,214 
+$ 
+— 
+$ 
+8,700 
+Callon Petroleum 
+Consolidating 
+Company 
+and 
+Callon Petroleum 
+(Parent 
+Guarantor 
+Eliminating 
+Company 
+Obligor) 
+Subsidiaries 
+Entries 
+Consolidated 
+For The Twelve Months Ended December 31, 2002 
+Statement of Cash Flow 
+Net cash provided
+(used in) operating
+activities 
+$ 
+(52,696 
+) 
+$ 
+64,863 
+$ 
+— 
+$ 
+12,167 
+Net cash provided by
+(used in) investing
+activities 
+4,044 
+(58,791 
+) 
+— 
+(54,747 
+) 
+Net cash provided by
+(used in) financing
+activities 
+48,326 
+(6,826 
+) 
+— 
+41,500 
+Net increase
+(decrease) in cash
+and cash equivalents 
+(326 
+) 
+(754 
+) 
+— 
+(1,080 
+) 
+Cash and cash
+equivalents at
+beginning of the
+period 
+517 
+6,370 
+— 
+6,887 
+Cash and cash
+equivalents at end of
+the period 
+$ 
+191 
+$ 
+5,616 
+$ 
+— 
+$ 
+5,807 
+71
+Table of Contents 
+11. NET PROFITS INTEREST 
+From 1989 through 1994, the Constituent Entities entered into separate agreements to purchase
+certain oil and gas properties with gross contract acquisition prices of $170,000,000 ($150,000,000
+net as of closing dates) and in simultaneous transactions, entered into agreements to sell
+overriding royalty interests (“ORRI”) in the acquired properties. These ORRI are in the form of
+net profits interests (“NPI”) equal to a significant percentage of the excess of gross proceeds
+over production costs, as defined, from the acquired oil and gas properties. A net deficit
+incurred in any month can be carried forward to subsequent months until such deficit is fully
+recovered. The Company has the right to abandon the purchased oil and gas properties if it deems
+the properties to be uneconomical.
+The Company has, pursuant to the purchase agreements, created abandonment trusts (see Note 7)
+whereby funds are provided out of gross production proceeds from the properties for the estimated
+amount of future abandonment obligations related to the working interests owned by the Company.
+The Trusts are administered by unrelated third party trustees for the benefit of the Company’s
+working interest in each property. The Trust agreements limit disbursement of funds to the
+satisfaction of abandonment obligations. Any funds remaining in the Trusts after all restoration,
+dismantlement and abandonment obligations have been met will be distributed to the owners of the
+properties in the same ratio as contributions to the Trusts. Estimated future revenues and costs
+associated with the NPI and the Trusts are also excluded from the oil and gas reserve disclosures
+at Note 14. As of December 31, 2004 and 2003, the Trusts’ assets (all cash and investments)
+totaled $7,742,000 and $7,420,000 respectively, all of which will be available to the Company to
+pay its portion, as working interest owner, of the restoration, dismantlement and abandonment costs
+discussed at Note 7. SFAS 143, discussed in Note 2 and 8, does not allow the Abandonment Trusts’
+assets to be used to offset the associated abandonment liability. The Company did not record any
+income or loss associated with the Trust asset or abandonment liability as a result of adoption of
+SFAS 143.
+At the time of acquisition of properties by the Company, the property owners estimated the future
+costs to be incurred for site restoration, dismantlement and abandonment, net of salvage value. A
+portion of the amounts necessary to pay such estimated costs was deposited in the Trusts upon
+acquisition of the properties, and the remainder is deposited from time to time out of the proceeds
+from production. The determination of the amount deposited upon the acquisition of the properties
+and the amount to be deposited as proceeds from production was based on numerous factors, including
+the estimated reserves of the properties.
+As operator, the Company receives all of the revenues and incurs all of the production costs for
+the purchased oil and gas properties but retains only that portion applicable to its net ownership
+share. As a result, the payables and receivables associated with operating the properties included
+in the Company’s Consolidated Balance Sheets include both the Company’s and all other outside
+owners’ shares. However, revenues and production costs associated with the acquired properties
+reflected in the accompanying Consolidated Statements of Operations represent only the Company’s
+share, after reduction for the NPI.
+72
+Table of Contents 
+12. EMPLOYEE BENEFIT PLANS 
+The Company has adopted a series of incentive compensation plans designed to align the interest of
+the executives and employees with those of its stockholders. The following is a brief description
+of each plan:
+The Savings and Protection Plan provides employees with the option to defer
+receipt of a portion of their compensation and the Company may, at its discretion,
+match a portion of the employee’s deferral with cash and Company Common Stock. The
+Company may also elect, at its discretion, to contribute a non-matching amount in
+cash and Company Common Stock to employees. The amounts held under the Savings and
+Protection Plan are invested in various funds maintained by a third party in
+accordance with the directions of each employee. An employee is fully vested,
+including Company discretionary contributions, immediately upon participation in the
+Savings and Protection Plan. The total amounts contributed by the Company,
+including the value of the common stock contributed, were $528,000, $562,000 and
+$611,000 in the years 2004, 2003 and 2002, respectively.
+The 1994 Stock Incentive Plan (the “1994 Plan”), approved by the shareholders
+in 1994, provides for 600,000 shares of Common Stock to be reserved for issuance
+pursuant to such plan. Under the 1994 Plan, the Company may grant both stock
+options qualifying under Section 422 of the Internal Revenue Code and options that
+are not qualified as incentive stock options, as well as performance shares. These
+options have an expiration date of 10 years from the date of grant.
+On August 23, 1996, the Board of Directors of the Company approved and adopted
+the Callon Petroleum Company 1996 Stock Incentive Plan (the “1996 Plan”). The 1996
+Plan was approved by the shareholders in 1997 and provides for the same types of
+awards as the 1994 Plan and is limited to a maximum of 1,200,000 shares (as amended
+from the original 900,000 shares) of common stock that may be subject to outstanding
+awards. Unvested options are subject to forfeiture upon certain termination of
+employment events and expire 10 years from the date of grant.
+The Company granted 533,000 stock options to employees on March 23, 2000 and
+120,000 stock options to directors on July 25, 2000 at $10.50 per share. The March
+23, 2000 grant was subject to shareholder approval of an amendment to the 1996 Stock
+Incentive Plan. The amendment, which was approved on May 9, 2000 at the Annual
+Meeting of Shareholders, increased the number of shares reserved for issuance under
+the 1996 plan to 2,200,000 shares. The excess of the market price over the exercise
+price on the approval date of the amendment was amortized over the three-year
+vesting period of the options. Compensation costs of $27,000 and $416,000 were
+recognized in 2003, and 2002, respectively, related to these options.
+In 2004, the Company awarded 430,000 performance shares from the 1994 and 1996
+Plans. These shares vest to the recipients over a five-year period (one-fifth in
+each year) beginning in July 2005. The deferred compensation portion of this grant
+will be amortized to expense over the vesting period. The non-cash amortization
+expense in 2004 was $532,000. In addition, 25,000 stock options were awarded to
+directors at $12.40 from the 1994 Plan.
+73
+Table of Contents 
+On February 14, 2002, the Board of Directors of the Company approved and adopted
+the 2002 Stock Incentive Plan (the “2002 Plan”). Pursuant to the 2002 Plan, 350,000
+shares of common stock shall be reserved for issuance upon the exercise of options or
+for grants of stock options, stock appreciation rights or units, bonus stock, or
+performance shares or units. This Plan qualified as a “broadly based” plan under the
+provisions of the New York Stock Exchange’s rules and regulations and therefore did
+not require shareholder approval. Because the 2002 Plan is a broadly based plan, the
+aggregate number of shares underlying awards granted to officers and directors cannot
+exceed 50% of the total number of shares underlying the awards granted to all
+employees during any three-year period.
+In 2002, the Company awarded 300,000 shares of restricted stock from the 1996 and the
+2002 Plan and 70,500 from treasury shares to be issued as vested. The issuance of
+the restricted stock using treasury shares did not require shareholder approval
+pursuant to the New York Stock Exchange’s rules and regulations, and therefore
+shareholder approval was not sought. These shares will generally vest to the
+recipients over a three-year period (one-third in each year) beginning in November
+2002. The deferred compensation portion of this grant will be amortized to expense
+over the vesting period. The non-cash amortization expense in 2004, 2003 and 2002 was
+$374,000, $454,000 and $496,000, respectively.
+In 1997, the Board of Directors authorized the implementation of the Callon Petroleum
+Company 1997 Employee Stock Purchase Plan (the “1997 Purchase Plan”), which was
+approved by the Company’s shareholders at the 1997 Annual Meeting. The Plan provides
+eligible employees of the Company with the opportunity to acquire a proprietary
+interest in the Company through participation in a payroll deduction-based employee
+stock purchase plan. An aggregate of 250,000 shares of common stock have been
+reserved for issuance over the 10-year term of the 1997 Purchase Plan. The purchase
+price per share at which common stock will be purchased on the participant’s behalf
+on each purchase date within an offering period is equal to 85 percent of the fair
+market value per share of common stock. As of December 31, 2004 there were no
+remaining shares available for purchase.
+A summary of the status of the Company’s stock option plans for the three most recent years and
+changes during the years then ended is presented in the table and narrative below:
+2004 
+2003 
+2002 
+Wtd Avg 
+Wtd Avg 
+Wtd Avg 
+Shares 
+Ex Price 
+Shares 
+Ex Price 
+Shares 
+Ex Price 
+Outstanding, beginning of year 
+2,450,867 
+$ 
+9.84 
+2,520,417 
+$ 
+9.90 
+2,332,667 
+$ 
+10.84 
+Granted (at market) 
+25,000 
+12.40 
+30,000 
+5.12 
+310,000 
+4.45 
+Exercised 
+(437,918 
+) 
+9.74 
+(500 
+) 
+4.10 
+— 
+— 
+Forfeited 
+(525,350 
+) 
+9.80 
+(99,050 
+) 
+9.74 
+(122,250 
+) 
+14.10 
+Expired 
+— 
+— 
+— 
+— 
+— 
+— 
+Outstanding, end of year 
+1,512,599 
+$ 
+9.93 
+2,450,867 
+$ 
+9.84 
+2,520,417 
+$ 
+9.90 
+Exercisable, end of year 
+1,446,486 
+$ 
+10.20 
+2,262,067 
+$ 
+10.31 
+2,224,334 
+$ 
+10.57 
+Weighted average fair value of
+options granted (at market) 
+$ 
+4.48 
+$ 
+2.97 
+$ 
+2.44 
+74
+Table of Contents 
+The following table sets forth additional information regarding options outstanding at
+December 31, 2004. Contractual life and exercise prices represent weighted averages for options
+outstanding and options exercisable.
+Options Outstanding 
+Options Exercisable 
+Range of 
+Number 
+Contractual 
+Exercise 
+Number 
+Exercise 
+exercise prices 
+Outstanding 
+Life (years) 
+Price 
+Exercisable 
+Price 
+$ 3.70 to 
+$ 
+6.41 
+237,999 
+7.5 
+$ 
+4.56 
+171,886 
+$ 
+4.72 
+$ 9.00 to 
+$ 
+12.40 
+1,209,600 
+3.9 
+$ 
+10.76 
+1,209,600 
+$ 
+10.76 
+$13.56 to 
+$ 
+15.31 
+65,000 
+3.2 
+$ 
+14.16 
+65,000 
+$ 
+14.16 
+The fair value of each option grant is estimated on the date of grant using the Black-Scholes
+option pricing model with the following weighted average assumptions used for options granted
+during the years presented are as follows:
+2004 
+2003 
+2002 
+Risk free interest rate 
+3.7 
+% 
+4.0 
+% 
+3.7 
+% 
+Expected life (years) 
+5.0 
+5.0 
+5.0 
+Expected volatility 
+45.1 
+% 
+65.3 
+% 
+61.0 
+% 
+Expected dividends 
+— 
+— 
+— 
+13. EQUITY TRANSACTIONS 
+On June 22, 2004, we closed the public offering of three million shares of common stock priced at
+$13.25 per share raising net proceeds of approximately $38.2 million, after expenses. In addition,
+we granted the underwriter, Johnson Rice & Company L.L.C., an over-allotment option to purchase an
+additional 450,000 shares. On June 30, 2004, the underwriter exercised the over-allotment option
+for an additional 450,000 shares priced at $13.25 per share, raising the net proceeds of the
+offering by approximately $5.7 million, after expenses. The proceeds from the transactions were
+used to redeem $33 million of the 11% Senior Subordinated Notes due December 15, 2005 and for
+general corporate purposes.
+In November 1995, the Company sold 1,315,500 shares of $2.125 Convertible Exchangeable Preferred
+Stock, Series A, and $0.01 par value per share (the Preferred Stock”) for net proceeds of $30.9
+million. Annual dividends are $2.125 per share and are cumulative. The net proceeds of the
+issuance of the Preferred Stock, after underwriters discount and expenses, were $30,899,000. Each
+share has a liquidation preference of $25.00, plus accrued and unpaid dividends. Dividends on the
+Preferred Stock are cumulative from the date of issuance and are payable quarterly, commencing
+January 15, 1996. The Preferred Stock is convertible at any time, at the option of the holders
+thereof, unless previously redeemed, into shares of Common Stock of the Company at an initial
+conversion price of $11 per share of Common Stock, subject to adjustments under certain conditions.
+The Preferred Stock is redeemable at any time on or after December 31, 1998, in whole or in part at
+the option of the Company at a redemption price of $26.488 per share beginning at December 31, 1998
+and at premiums declining to the $25.00 liquidation preference by the year 2005 and thereafter,
+plus accrued and unpaid dividends. The Preferred Stock is also exchangeable, in whole, but not in
+part, at the option of the Company on or after January 15, 1998 for the Company’s 8.5% Convertible
+Subordinated Debentures due 2010 (the “Debentures”) at a rate of $25.00 principal amount of
+Debentures for each share of Preferred
+75
+Table of Contents 
+Stock. The Debentures will be convertible into Common Stock of the Company on the same terms as the Preferred Stock and will pay interest semi-annually.
+In a December 1998 private transaction, a preferred stockholder elected to convert 59,689 shares of
+Preferred Stock into 136,867 shares of the Company’s Common Stock. In 1999 certain other preferred
+stockholders, through private transactions, agreed to convert 210,350 shares of Preferred Stock
+into 502,637 shares of the Company’s Common Stock under similar terms. Likewise in 2000, 444,600
+shares of Preferred Stock were converted into 1,036,098 shares of the Company’s Common Stock. Any
+non-cash premium negotiated in excess of the conversion rate was recorded as additional preferred
+stock dividends and excluded from the Consolidated Statements of Cash Flows.
+The Company adopted a stockholder rights plan on March 30, 2000, designed to assure that the
+Company’s stockholders receive fair and equal treatment in the event of any proposed takeover of
+the Company and to guard against partial tender offers, squeeze-outs, open market accumulations,
+and other abusive tactics to gain control without paying all stockholders a fair price. The rights
+plan was not adopted in response to any specific takeover proposal. Under the rights plan, the
+Company declared a dividend of one right (“Right”) on each share of the Company’s Common Stock.
+Each Right will entitle the holder to purchase one one-thousandth of a share of a Series B
+Preferred Stock, par value $0.01 per share, at an exercise price of $90 per one one-thousandth of a
+share.
+The Rights are not currently exercisable and will become exercisable only in the event a person or
+group acquires, or engages in a tender or exchange offer to acquire, beneficial ownership of 15
+percent or more (one existing stockholder was granted an exception for up to 21 percent) of the
+Company’s Common Stock. After the Rights become exercisable, each Right will also entitle its
+holder to purchase a number of common shares of the Company having a market value of twice the
+exercise price. The dividend distribution was made to stockholders of record at the close of
+business on April 10, 2000. The Rights will expire on March 30, 2010.
+14. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED) 
+The Company’s proved oil and gas reserves at December 31, 2004, 2003 and 2002 have been estimated
+by independent petroleum consultants in accordance with guidelines established by the Securities
+and Exchange Commission (“SEC”). Accordingly, the following reserve estimates are based upon
+existing economic and operating conditions. These estimates have been adjusted to exclude reserves
+attributable to the volumetric production payment described in Note 2.
+There are numerous uncertainties inherent in establishing quantities of proved reserves. The
+following reserve data represents estimates only and should not be construed as being exact. In
+addition, the standardized measure of discounted future net cash flows should not be construed as
+the current market value of the Company’s oil and gas properties or the cost that would be incurred
+to obtain equivalent reserves. See Note 7 regarding the Deep Water Royalty Relief Act and the loss
+of reserves.
+76
+Table of Contents 
+Estimated Reserves 
+Changes in the estimated net quantities of crude oil and natural gas reserves, all of which are
+located onshore and offshore in the continental United States, are as follows:
+Reserve Quantities 
+Years Ended December 31, 
+2004 
+2003 
+2002 
+Proved developed and undeveloped reserves: 
+Crude Oil (MBbls): 
+Beginning of period 
+23,709 
+24,043 
+30,209 
+Revisions to previous estimates 
+(2,370 
+)(b) 
+(1 
+) 
+(8,699 
+)(a) 
+Purchase of reserves in place 
+— 
+— 
+— 
+Sales of reserves in place 
+— 
+(65 
+) 
+— 
+Extensions and discoveries 
+145 
+— 
+2,759 
+(a) 
+Production 
+(1,736 
+) 
+(268 
+) 
+(226 
+) 
+End of period 
+19,748 
+23,709 
+24,043 
+Natural Gas (MMcf): 
+Beginning of period 
+74,691 
+91,539 
+120,299 
+Revisions to previous estimates 
+2,138 
+(6,407 
+)(b) 
+(19,284 
+)(a) 
+Purchase of reserves in place 
+— 
+— 
+— 
+Sales of reserves in place 
+— 
+(49 
+) 
+— 
+Extensions and discoveries 
+7,177 
+1,923 
+3,584 
+(a) 
+Production 
+(11,387 
+) 
+(12,315 
+) 
+(13,060 
+) 
+End of period 
+72,619 
+74,691 
+91,539 
+Proved developed reserves: 
+Crude Oil (MBbls): 
+Beginning of period 
+9,919 
+1,056 
+885 
+End of period 
+10,292 
+9,919 
+1,056 
+Natural Gas (MMcf): 
+Beginning of period 
+31,415 
+37,631 
+51,221 
+End of period 
+33,982 
+31,415 
+37,631 
+(a) 
+For the year ended December 31, 2002, revisions to previous estimates and extensions and
+discoveries were adjusted from the amounts reported in the Company’s Annual Report on Form
+10-K dated March 27, 2003 to reflect the subsequent changes in properties that were part of
+property acquisitions or exploratory drilling programs and should have been classified as
+extensions instead of revisions. 
+(b) 
+Includes Medusa royalty adjustment 
+77
+Table of Contents 
+Standardized Measure 
+The following tables present the Company’s standardized measure of discounted future net cash flows
+and changes therein relating to proved oil and gas reserves and were computed using reserve
+valuations based on regulations prescribed by the SEC. These regulations provide that the oil,
+condensate and gas price structure utilized to project future net cash flows reflects current
+prices (approximately $6.51 per Mcf for natural gas and $36.72 per Bbl for oil for the 2004
+disclosures, $5.99 per Mcf and $30.50 per Bbl for 2003 disclosures, and $4.80 per Mcf and $34.22
+per Bbl for 2002 disclosures) at each date presented and have not been escalated. Future
+production, development and net abandonment costs are based on current costs without escalation.
+The resulting net future cash flows have been discounted to their present values based on a 10%
+annual discount factor.
+Standardized Measure 
+Years Ended December 31, 
+2004 
+2003 
+2002 
+(In thousands) 
+Future cash inflows 
+$ 
+1,198,096 
+$ 
+1,170,118 
+$ 
+1,261,571 
+Future costs - 
+Production 
+(231,616 
+) 
+(219,421 
+) 
+(165,559 
+) 
+Development and net abandonment 
+(74,335 
+) 
+(111,850 
+) 
+(125,813 
+) 
+Future net inflows before income taxes 
+892,145 
+838,847 
+970,199 
+Future income taxes 
+(166,284 
+) 
+(89,567 
+) 
+(119,020 
+) 
+Future net cash flows 
+725,861 
+749,280 
+851,179 
+10% discount factor 
+(209,968 
+) 
+(230,254 
+) 
+(295,133 
+) 
+Standardized measure of discounted
+future net cash flows 
+$ 
+515,893 
+$ 
+519,026 
+$ 
+556,046 
+Changes in Standardized Measure 
+Years Ended December 31, 
+2004 
+2003 
+2002 
+(In thousands) 
+Standardized measure – beginning of period 
+$ 
+519,026 
+$ 
+556,046 
+$ 
+254,857 
+Sales and transfers, net of production costs 
+(97,494 
+) 
+(62,396 
+) 
+(38,375 
+) 
+Net change in sales and transfer prices,
+net of production costs 
+86,551 
+(41,011 
+) 
+401,837 
+Exchange and sale of in place reserves 
+— 
+(1,226 
+) 
+— 
+Purchases, extensions, discoveries, and
+improved
+recovery, net of future production and
+development costs incurred 
+77,576 
+25,632 
+8,456 
+Revisions of quantity estimates 
+(41,314 
+) 
+(18,018 
+) 
+(103,452 
+) 
+Accretion of discount 
+57,046 
+62,394 
+26,915 
+Net change in income taxes 
+(45,262 
+) 
+16,460 
+(53,608 
+) 
+Changes in production rates, timing and other 
+(40,236 
+) 
+(18,855 
+) 
+59,416 
+Standardized measure — end of period 
+$ 
+515,893 
+$ 
+519,026 
+$ 
+556,046 
+78
+Table of Contents 
+15. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) 
+First 
+Second 
+Third 
+Fourth 
+Quarter 
+Quarter 
+Quarter 
+Quarter 
+(In thousands, except per share data) 
+2004 
+Total revenues 
+$ 
+31,919 
+$ 
+37,606 
+$ 
+25,138 
+$ 
+25,139 
+Income from operations 
+10,231 
+14,543 
+5,367 
+6,371 
+Net income (loss) 
+2,102 
+9,730 
+546 
+9,123 
+(a) 
+Net income (loss) per common share-basic 
+$ 
+0.13 
+$ 
+0.66 
+$ 
+0.01 
+$ 
+0.50 
+(a) 
+Net income (loss) per common share-diluted 
+0.12 
+0.58 
+0.01 
+0.45 
+(a) 
+First 
+Second 
+Third 
+Fourth 
+Quarter 
+Quarter 
+Quarter 
+Quarter 
+(In thousands, except per share data) 
+2003 
+Total revenues 
+$ 
+21,268 
+$ 
+18,409 
+$ 
+15,082 
+$ 
+18,938 
+Income from operations 
+8,946 
+6,422 
+4,366 
+6,277 
+Income (loss) before cumulative effect of change
+in accounting principle 
+1,201 
+(647 
+) 
+(2,026 
+) 
+(16,700 
+)(b) 
+Net income (loss) 
+1,382 
+(647 
+) 
+(2,026 
+) 
+(16,700 
+)(b) 
+Net income (loss) per common share-basic: 
+Net income (loss) available to common before
+cumulative effect of change in accounting
+principle 
+$ 
+0.07 
+($ 
+0.07 
+) 
+($ 
+0.17 
+) 
+($ 
+1.24 
+)(b) 
+Cumulative effect of change in accounting
+principle,
+net of tax 
+0.01 
+0.00 
+0.00 
+0.00 
+Net income (loss) per share 
+$ 
+0.08 
+($ 
+0.07 
+) 
+($ 
+0.17 
+) 
+($ 
+1.24 
+)(b) 
+Net income (loss) per common share-diluted: 
+Net income (loss) available to common before
+cumulative effect of change in accounting
+principle 
+$ 
+0.07 
+($ 
+0.07 
+) 
+($ 
+0.17 
+) 
+($ 
+1.24 
+)(b) 
+Cumulative effect of change in accounting
+principle,
+net of tax 
+0.01 
+0.00 
+0.00 
+0.00 
+Net income (loss) per share 
+$ 
+0.08 
+($ 
+0.07 
+) 
+($ 
+0.17 
+) 
+($ 
+1.24 
+)(b) 
+(a) 
+The fourth quarter of 2004 includes a tax benefit of $6.7 million resulting from the
+elimination of the valuation allowance established in 2003. See Note 3. 
+(b) 
+The fourth quarter of 2003 includes the establishment of a deferred tax valuation
+allowance of $11.5. See Note 3. 
+79
+Table of Contents 
+ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+There have been no disagreements with the independent auditors on any matters of accounting
+principles or practices, financial statement disclosure, or auditing scope or procedures.
+ITEM 9.A CONTROLS AND PROCEDURES 
+The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the
+Securities Exchange Act of 1934, or the Exchange Act. This term refers to the controls and
+procedures of a company that are designed to ensure that information required to be disclosed by a
+company in the reports that it files or submits under the Exchange Act is recorded, processed,
+summarized and reported within the time periods specified by the Securities and Exchange
+Commission. Our management, including our Chief Executive Officer and Chief Financial Officer, has
+evaluated the effectiveness of our disclosure controls and procedures as of the end of the period
+covered by this annual report. Based upon that evaluation, our Chief Executive Officer and Chief
+Financial Officer have concluded that our disclosure controls and procedures were effective as of
+the end of the period covered by this annual report.
+Management’s Report On Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over
+financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the
+supervision and with the participation of our management, including our principal executive officer
+and principal financial officer, we conducted an evaluation of the effectiveness of our internal
+control over financial reporting as of December 31, 2004 based on the frame work in the Internal
+Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
+Commission. Based on our evaluation under the framework in Internal Control-Integrated Framework,
+our management concluded that our internal control over financial reporting was effective as of
+December 31, 2004.
+Ernst & Young LLP, our independent registered public accounting firm, has issued an attestation
+report on our management’s assessment of the effectiveness of our internal control over financial
+reporting which is included herein.
+Changes In Internal Control Over Financial Reporting 
+There were no changes to our internal control over financial reporting during our last fiscal
+quarter that has materially affected, or is reasonably likely to materially affect, our internal
+control over financial reporting.
+80
+Table of Contents 
+Report of Independent Registered Public Accounting Firm
+The Stockholders and Board of Directors 
+Callon Petroleum Company
+We have audited management’s assessment, included in the accompanying Management’s Report on
+Internal Control over Financial Reporting, that Callon Petroleum Company maintained effective
+internal control over financial reporting as of December 31, 2004, based on criteria established in
+Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the
+Treadway Commission (the COSO criteria). Callon Petroleum Company’s management is responsible for
+maintaining effective internal control over financial reporting and for its assessment of the
+effectiveness of internal control over financial reporting. Our responsibility is to express an
+opinion on management’s assessment and an opinion on the effectiveness of the company’s internal
+control over financial reporting based on our audit.
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
+Board (United States). Those standards require that we plan and perform the audit to obtain
+reasonable assurance about whether effective internal control over financial reporting was
+maintained in all material respects. Our audit included obtaining an understanding of internal
+control over financial reporting, evaluating management’s assessment, testing and evaluating the
+design and operating effectiveness of internal control, and performing such other procedures as we
+considered necessary in the circumstances. We believe that our audit provides a reasonable basis
+for our opinion.
+A company’s internal control over financial reporting is a process designed to provide reasonable
+assurance regarding the reliability of financial reporting and the preparation of financial
+statements for external purposes in accordance with generally accepted accounting principles. A
+company’s internal control over financial reporting includes those policies and procedures that (1)
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
+transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
+transactions are recorded as necessary to permit preparation of financial statements in accordance
+with generally accepted accounting principles, and that receipts and expenditures of the company
+are being made only in accordance with authorizations of management and directors of the company;
+and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
+acquisition, use, or disposition of the company’s assets that could have a material effect on the
+financial statements.
+Because of its inherent limitations, internal control over financial reporting may not prevent or
+detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
+subject to the risk that controls may become inadequate because of changes in conditions, or that
+the degree of compliance with the policies or procedures may deteriorate.
+81
+Table of Contents 
+In our opinion, management’s assessment that Callon Petroleum Company maintained effective internal
+control over financial reporting as of December 31, 2004, is fairly stated, in all material
+respects, based on the COSO criteria. Also, in our opinion, Callon Petroleum Company maintained, in all material
+respects, effective internal control over financial reporting as of December 31, 2004, based on the
+COSO criteria.
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight
+Board (United States), the consolidated balance sheets of Callon Petroleum Company as of December
+31, 2004 and 2003, and the related consolidated statements of
+operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31,
+2004 of Callon Petroleum Company and our report dated March 8, 2005, expressed an unqualified
+opinion thereon.
+/s/Ernst & Young LLP
+New Orleans, Louisiana 
+March 8, 2005
+82
+Table of Contents 
+ITEM 9.B OTHER INFORMATION 
+We have disclosed all information required to be disclosed in a current report on Form 8-K during
+the fourth quarter of the year ended December 31, 2004 in previously filed reports on Form 8-K.
+83
+Table of Contents 
+PART III. 
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. 
+For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 5, 2005 which will be filed with the
+Securities and Exchange Commission and is incorporated herein by reference.
+ITEM 11. EXECUTIVE COMPENSATION. 
+For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 5, 2005 which will be filed with the
+Securities and Exchange Commission and is incorporated herein by reference.
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS. 
+For information concerning the security ownership of certain beneficial owners and management, see
+the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of
+Stockholders on May 5, 2005 which will be filed with the Securities and Exchange Commission and is
+incorporated herein by reference.
+84
+Table of Contents 
+Equity Compensation Plan Information 
+The following table provides information as of December 31, 2004 regarding the number of shares of
+Common Stock that may be issued under the Company’s equity compensation plans.
+Number of securities 
+remaining available for 
+future issuance under 
+Number of securities to 
+Weighted-average 
+equity compensation 
+be issued upon exercise 
+exercise price of 
+plans (excluding 
+of outstanding options, 
+outstanding options, 
+securities reflected in 
+warrants and rights 
+warrants and rights 
+column (a)) 
+Plan Category 
+(a) 
+(b) 
+(c) 
+Equity compensation
+plans approved by
+security holders 
+1,370,266 
+$ 
+10.51 
+501,726 
+Equity compensation
+plans not
+approved by
+security holders 
+142,333 
+$ 
+4.36 
+65,666 
+Total 
+1,512,599 
+$ 
+9.93 
+567,392 
+See Note 12 to the Consolidated Financial Statements for a description of the material provisions
+of each equity compensation plan under which our equity securities are authorized for issuance that
+was adopted without the approval of shareholders.
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 5, 2005 which will be filed with the
+Securities and Exchange Commission and is incorporated herein by reference.
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES. 
+For information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 5, 2005 which will be filed with the
+Securities and Exchange Commission and is incorporated herein by reference.
+85
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0000928022/2004/0000950134-05-004630/item13.txt b/raw/filings/0000928022/2004/0000950134-05-004630/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..5584bb1d05259607e3fe21e6f2cf9fbbc6614f5c
--- /dev/null
+++ b/raw/filings/0000928022/2004/0000950134-05-004630/item13.txt
@@ -0,0 +1,4 @@
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 5, 2005 which will be filed with the
+Securities and Exchange Commission and is incorporated herein by reference.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2004/0000950134-05-004630/item9a.txt b/raw/filings/0000928022/2004/0000950134-05-004630/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2004/0000950134-05-004630/rp_note.txt b/raw/filings/0000928022/2004/0000950134-05-004630/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2004/0000950134-05-004630/rpt_disclosure.txt b/raw/filings/0000928022/2004/0000950134-05-004630/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2005/0000950134-06-005141/filing.txt b/raw/filings/0000928022/2005/0000950134-06-005141/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..aefe9575bfe1a7c359ce5d7192af4fbf7fc65e4b
--- /dev/null
+++ b/raw/filings/0000928022/2005/0000950134-06-005141/filing.txt
@@ -0,0 +1,5347 @@
+10-K
+1
+d33954e10vk.htm
+FORM 10-K
+e10vk 
+Table of Contents 
+UNITED STATES SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF 
+THE SECURITIES EXCHANGE ACT OF 1934 
+FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005 
+Commission File Number 001-14039 
+CALLON PETROLEUM COMPANY 
+(Exact name of Registrant as specified in its charter) 
+Delaware 
+64-0844345 
+(State or other jurisdiction of 
+incorporation or organization)
+(I.R.S. Employer 
+Identification No.) 
+200 North Canal Street 
+Natchez, Mississippi 39120 
+(601) 442-1601 
+(Address of Principal Executive 
+Offices)(Zip Code)
+(Registrant’s telephone number 
+including area code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Name of exchange on which registered 
+Common Stock, Par Value $.01 Per Share
+New York Stock Exchange 
+Securities registered pursuant to Section 12(g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule
+405 of the Securities Act. Yes o No þ 
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
+Section 15(d) of the Act. Yes o No þ 
+Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by
+Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
+such shorter period that the Registrant was required to file such reports), and (2) has been
+subject to such filing requirements for the past 90 days. Yes þ No o 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
+not contained herein, and will not be contained, to the best of Registrant’s knowledge, in
+definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
+or any amendment to this Form 10-K. o 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
+or a non-accelerated filer. See definitions of “accelerated filer and large accelerated filer” in
+Rule 12b-2 of the Exchange Act. (Check one):
+Large accelerated filer o Accelerated filer þ Non-accelerated filer o 
+Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule
+12b-2). Yes o No þ 
+The aggregate market value of the voting and non-voting common equity held by nonaffiliates of the
+registrant was approximately $270.9 million as of June 30, 2005 (based on the last reported sale
+price of such stock on the New York Stock Exchange on such date of $14.78).
+As of March 2, 2006, there were 19,373,193 shares of the Registrant’s Common Stock, par value $.01
+per share, outstanding.
+Document incorporated by reference: Portions of the definitive Proxy Statement of Callon Petroleum
+Company (to be filed no later than 120 days after December 31, 2005) relating to the Annual Meeting
+of Stockholders to be held on May 4, 2006, which are incorporated into Part III of this Form 10-K.
+TABLE OF CONTENTS 
+PART I 
+ITEM 1 and 2. BUSINESS and PROPERTIES 
+ITEM 3. LEGAL PROCEEDINGS 
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 
+PART II 
+ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS 
+ITEM 6. SELECTED FINANCIAL DATA 
+ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS 
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+ITEM 9.A CONTROLS AND PROCEDURES 
+ITEM 9.B OTHER INFORMATION 
+PART III. 
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 
+ITEM 11. EXECUTIVE COMPENSATION 
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+PART IV. 
+ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 
+SIGNATURES 
+Consent of Ernst & Young LLP 
+Consent of Huddleston & Co., Inc. 
+Certification of Chief Executive Officer 
+Certification of Chief Executive Officer 
+Table of Contents 
+PART I. 
+ITEM 1 and 2. BUSINESS and PROPERTIES 
+Overview 
+Callon Petroleum Company has been engaged in the exploration, development, acquisition and
+production of oil and gas properties since 1950. Our properties are geographically
+concentrated primarily offshore in the Gulf of Mexico and onshore in Louisiana and Alabama. We
+were incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of
+a publicly traded limited partnership, a joint venture with a consortium of European investors and
+an independent energy company owned by members of current management. As used herein, the
+“Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors
+and subsidiaries unless the context requires otherwise.
+In 1989, we began increasing our reserves through the acquisition of producing properties that were
+geologically complex, had (or were analogous to fields with) an established production history from
+stacked pay zones and were candidates for exploitation. We focused on reducing operating costs and
+implementing production enhancements through the application of technologically advanced production
+and recompletion techniques.
+Over the past 10 years, we have placed emphasis on the acquisition of acreage with exploration and
+development drilling opportunities in the Gulf of Mexico shelf and deepwater areas. At December
+31, 2005, we owned working interests in a total of 88 blocks/leases covering 152,000 net acres. To
+minimize risk we join with industry partners to explore federal offshore blocks acquired in the
+Gulf of Mexico. We perform extensive geological and geophysical studies using computer-aided
+exploration techniques (CAEX), including, where appropriate, the acquisition of 3-D seismic or
+high-resolution 2-D data to facilitate these efforts. We continue to develop prospects on the
+shelf through our 3-D seismic partnership using Amplitude versus Offset (“AVO”) technology. In
+1998, we began exploration in the Gulf of Mexico deepwater area (generally 900 to 5,500 feet of
+water) and during the fourth quarter of 2003, our first two deepwater projects, the Medusa and
+Habanero fields, began production. Please see “Significant Properties” for a more detailed
+discussion.
+We ended the year 2005 with estimated net proved reserves of 188.6 billion cubic feet of natural
+gas equivalent (“Bcfe”). This represents a decrease of 1% from 2004 year-end estimated net proved
+reserves of 191.1 Bcfe. We produced 18.8 million cubic feet of natural gas equivalent (“Mmcfe”)
+and had net reserve additions of 16.3 Mmcfe.
+The major focus of our future operations is expected to continue to be the exploration for and
+development of oil and gas properties, primarily in the Gulf of Mexico.
+Availability of Reports 
+All of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
+8-K, and amendments to such reports as well as other filings we make pursuant to Section 13(a) and
+15(d) of the Securities Exchange Act of 1934 are available free of charge on our Internet website.
+The address of our Internet website is www.callon.com. Our Securities and Exchange Commission
+(“SEC”) filings are available on our website as soon as they are posted to the EDGAR database on
+the SEC’s website.
+2
+Table of Contents 
+Business Strategy 
+Our goal is to increase shareholder value by increasing our reserves, production, cash flow and
+earnings. We seek to achieve these goals through the following strategies:
+• 
+focus on Gulf of Mexico exploration with a balance between shelf and deepwater areas
+using the latest available technology; 
+• 
+aggressively explore our existing prospect inventory; and 
+• 
+replenish our prospect inventory with increasing emphasis on prospect generation using
+AVO technology. 
+Exploration and Development Activities 
+In 2005, capital expenditures for exploration and development costs related to oil and gas
+properties totaled approximately $90 million, of which $17 million was included in accounts payable
+at December 31, 2005. We incurred approximately:
+• 
+$34 million in the Gulf of Mexico shelf and onshore south Louisiana areas which included
+the drilling of 11 exploratory wells, four of which were unsuccessful; 
+• 
+$16 million for completion and development costs associated with our successful drill
+wells, two of which came online in 2005 and the remaining are scheduled to come online in
+the first half of 2006; 
+• 
+$5 million in our deepwater area, which includes the development and completion costs
+for North Medusa; 
+• 
+$15 million for leasehold and seismic costs; 
+• 
+$7 million for the acquisition of producing oil and gas properties and miscellaneous costs; and 
+• 
+$6 million for capitalized interest and $7 million for capitalized general and
+administration costs allocable directly to exploration and development projects. 
+Risk Factors 
+A decrease in oil and gas prices may adversely affect our results of operations and financial
+condition . Our success is highly dependent on prices for oil and gas, which are extremely volatile.
+Any substantial or extended decline in the price of oil or gas would have a material adverse effect
+on us. Oil and gas markets are both seasonal and cyclical. The prices of oil and gas depend on
+factors we cannot control such as weather, economic conditions, and levels of production, actions
+by OPEC and other countries and government actions. Prices of oil and gas will affect the following
+aspects of our business:
+• 
+our revenues, cash flows and earnings; 
+• 
+the amount of oil and gas that we are economically able to produce; 
+• 
+our ability to attract capital to finance our operations and the cost of the capital; 
+• 
+the amount we are allowed to borrow under our senior secured credit facility; 
+• 
+the value of our oil and gas properties; and 
+• 
+the profit or loss we incur in exploring for and developing our reserves. 
+3
+Table of Contents 
+Our reserve information represents estimates that may turn out to be incorrect if the assumptions
+upon which these estimates are based are inaccurate. Any material inaccuracies in these reserve
+estimates or underlying assumptions will materially affect the quantities and present value of our
+reserves. The process of estimating oil and gas reserves is complex. It requires interpretations
+of available technical data and various assumptions, including assumptions relating to economic
+factors. Any significant inaccuracies in these interpretations or assumptions could materially
+affect the estimated quantities and present value of reserves shown in this annual report.
+In order to prepare these estimates, we must project production rates and the timing of development
+expenditures. The assumptions regarding the timing and costs to commence production from our
+deepwater wells used in preparing our reserves are often subject to revisions over time as
+described under “Our deepwater operations have special operational risks that may negatively affect
+the value of those assets.” We must also analyze available geological, geophysical, production and
+engineering data, the extent, quality and reliability of which can vary. The process also requires
+us to make economic assumptions, such as oil and gas prices, drilling and operating expenses,
+capital expenditures, taxes and availability of funds. Therefore, estimates of oil and gas
+reserves are inherently imprecise.
+Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating
+expenses and quantities of recoverable oil and gas reserves most likely will vary from the
+estimates. Any significant variance could materially affect the estimated quantities and present
+value of reserves shown in this report. In addition, estimates of proved reserves may be adjusted
+to reflect production history, results of exploration and development, prevailing oil and gas
+prices and other factors, many of which are beyond our control.
+Also, under MMS rules governing our deepwater Medusa property and several of our shallow water,
+deep natural gas properties and prospects, we are eligible for royalty suspensions depending on the
+difference between the average monthly New York Mercantile Exchange (NYMEX) sales price for oil or
+gas and price thresholds set by the MMS. As a result, our reserve estimates may increase or
+decrease depending upon the relation of price thresholds versus the average NYMEX prices.
+You should not assume that the present value of future net cash flows from our proved reserves
+referred to in this report is the current market value of our estimated oil and gas reserves. In
+accordance with SEC requirements, we generally base the estimated discounted future net cash flows
+from our proved reserves on prices and costs on the date of the estimate. Actual future prices and
+costs may differ materially from those used in the present value estimate.
+The discounted present value of our oil and gas reserves is prepared in accordance with guidelines
+established by the SEC. A purchaser of reserves would use numerous other factors to value the
+reserves. The discounted present value of reserves, therefore, does not necessarily represent the
+fair market value of those reserves.
+On December 31, 2005, approximately 58% of the discounted present value of our estimated net proved
+reserves were proved undeveloped. Proved undeveloped reserves represented 60% of total proved
+reserves. Most of these proved undeveloped reserves were attributable to our deepwater properties.
+Development of these properties is subject to additional risks as described above.
+4
+Table of Contents 
+Information about reserves constitutes forward-looking information. See “Forward-Looking
+Statements” for information regarding forward-looking information. 
+Unless we are able to replace reserves which we have produced, our cash flows and production will
+decrease over time. Our future success depends upon our ability to find, develop and acquire oil
+and gas reserves that are economically recoverable. As is generally the case for Gulf properties,
+our producing properties usually have high initial production rates, followed by a steep decline in
+production. As a result, we must continually locate and develop or acquire new oil and gas reserves
+to replace those being depleted by production. We must do this even during periods of low oil and
+gas prices when it is difficult to raise the capital necessary to finance these activities and
+during periods of high operating costs when it is expensive to contract for drilling rigs and other
+equipment and personnel necessary to explore for oil and gas. Without successful
+exploration or acquisition activities, our reserves, production and revenues will decline rapidly.
+We cannot assure you that we will be able to find and develop or acquire additional reserves at an
+acceptable cost.
+Also, because of the aggregate short life of our reserves, our return on the investment we make in
+our oil and gas wells and the value of our oil and gas wells will depend significantly on prices
+prevailing during relatively short production periods.
+A significant part of the value of our production and reserves is concentrated in a small number of
+offshore properties, and any production problems or inaccuracies in reserve estimates related to
+those properties would adversely impact our business. During 2005, 86% of our daily production
+came from five of our properties in the Gulf of Mexico. Moreover, one property accounted for 43% of
+our production during this period. In addition, at December 31, 2005, most of our proved reserves
+were located in three fields in the Gulf of Mexico, with approximately 76% of our total net proved
+reserves attributable to these properties. If mechanical problems, storms or other events
+curtailed a substantial portion of this production or if the actual reserves associated with any
+one of these producing properties are less than our estimated reserves, our results of operations
+and financial condition could be adversely affected.
+Our focus on exploration projects increases the risks inherent in our oil and gas activities. Our
+business strategy focuses on replacing reserves through exploration, where the risks are greater
+than in acquisitions and development drilling. Although we have been successful in exploration in
+the past, we cannot assure you that we will continue to increase reserves through exploration or at
+an acceptable cost. Additionally, we are often uncertain as to the future costs and timing of
+drilling, completing and producing wells. Our drilling operations may be curtailed, delayed or
+canceled as a result of a variety of factors, including:
+• 
+unexpected drilling conditions; 
+• 
+pressure or inequalities in formations; 
+• 
+equipment failures or accidents; 
+• 
+adverse weather conditions; 
+• 
+compliance with governmental requirements; and 
+• 
+shortages or delays in the availability of drilling rigs and the delivery of equipment. 
+5
+Table of Contents 
+We do not operate all of our properties and have limited influence over the operations of some of
+these properties, particularly our deepwater properties. Our lack of control could result in the
+following:
+• 
+the operator may initiate exploration or development at a faster or slower pace than we
+prefer; 
+• 
+the operator may propose to drill more wells or build more facilities on a project than
+we have funds for or that we deem appropriate, which may mean that we are unable to
+participate in the project or share in the revenues generated by the project even though we
+paid our share of exploration costs; and 
+• 
+if an operator refuses to initiate a project, we may be unable to pursue the project. 
+Any of these events could materially reduce the value of our non-operated properties.
+Our deepwater operations have special operational risks that may negatively affect the value of
+those assets. Drilling operations in the deepwater area are by their nature more difficult and
+costly than drilling operations in shallow water. Deepwater drilling operations require the
+application of more advanced drilling technologies involving a higher risk of technological failure
+and usually have significantly higher drilling costs than shallow water drilling operations.
+Deepwater wells are completed using sub-sea completion techniques that require substantial time and
+the use of advanced remote installation equipment. These operations involve a high risk of
+mechanical difficulties and equipment failures that could result in significant cost overruns.
+In deepwater, the time required to commence production following a discovery is much longer than in
+shallow water and on-shore. Deepwater discoveries require the construction of expensive production
+facilities and pipelines prior to production. We cannot estimate the costs and timing of the
+construction of these facilities with certainty, and the accuracy of our estimates will be affected
+by a number of factors beyond our control, including the following:
+• 
+decisions made by the operators of our deepwater wells; 
+• 
+the availability of materials necessary to construct the facilities; 
+• 
+the proximity of our discoveries to pipelines; and 
+• 
+the price of oil and natural gas. 
+Delays and cost overruns in the commencement of production will affect the value of our deepwater
+prospects and the discounted present value of reserves attributable to those prospects.
+Competitive industry conditions may negatively affect our ability to conduct operations. We
+operate in the highly competitive areas of oil and gas exploration, development and production. We
+compete for the purchase of leases in the Gulf of Mexico from the U. S. government and from other
+oil and gas companies. These leases include exploration prospects as well as properties with
+proved reserves. Factors that affect our ability to compete in the marketplace include:
+6
+Table of Contents 
+• 
+our access to the capital necessary to drill wells and acquire properties; 
+• 
+our ability to acquire and analyze seismic, geological and other information relating to
+a property; 
+• 
+our ability to retain the personnel necessary to properly evaluate seismic and other
+information relating to a property; 
+• 
+the location of, and our ability to access, platforms, pipelines and other facilities
+used to produce and transport oil and gas production; 
+• 
+the standards we establish for the minimum projected return on an investment of our
+capital; and 
+• 
+the availability of alternate fuel sources. 
+Our competitors include major integrated oil companies, substantial independent energy companies,
+and affiliates of major interstate and intrastate pipelines and national and local gas gatherers,
+many of which possess greater financial, technological and other resources than we do.
+Our competitors may use superior technology, which we may be unable to afford or which would
+require costly investment by us in order to compete. Our industry is subject to rapid and
+significant advancements in technology, including the introduction of new products and services
+using new technologies. As our competitors use or develop new technologies, we may be placed at a
+competitive disadvantage, and competitive pressures may force us to implement new technologies at a
+substantial cost. In addition, our competitors may have greater financial, technical and personnel
+resources that allow them to enjoy technological advantages and may in the future allow them to
+implement new technologies before we can. We cannot be certain that we will be able to implement
+technologies on a timely basis or at a cost that is acceptable to us. One or more of the
+technologies that we currently use or that we may implement in the future may become obsolete, and
+we may be adversely affected. For example, marine seismic acquisition technology has been
+characterized by rapid technological advancements in recent years, and further significant
+technological developments could substantially impair our 3-D seismic data’s value.
+We may not be able to replace our reserves or generate cash flows if we are unable to raise
+capital. We will be required to make substantial capital expenditures to develop our existing
+reserves, and to discover new oil and gas reserves. Historically, we have financed these
+expenditures primarily with cash from operations, proceeds from bank borrowings and proceeds from
+the sale of debt and equity securities. See “Management’s Discussion and Analysis of Financial
+Condition and Results of Operations — Liquidity and Capital Resources” for a discussion of
+our capital budget. We cannot assure you that we will be able to raise capital in the future. We
+also make offers to acquire oil and gas properties in the ordinary course of our business. If these
+offers are accepted, our capital needs may increase substantially.
+We expect to continue using our senior secured credit facility to borrow funds to supplement our
+available cash. The amount we may borrow under our senior secured credit facility may not exceed a
+borrowing base determined by the lenders under such facility based on their projections of our
+future production, production costs, taxes, commodity prices and any other factors deemed relevant
+by our lenders. We cannot control the assumptions the lenders use to calculate our borrowing base.
+The lenders may, without our consent, adjust the borrowing base semiannually or in situations where
+we purchase or sell assets or issue debt securities. If our borrowings under the senior secured
+credit facility exceed the borrowing base, the lenders may require that we repay the excess. If
+this were to occur, we might have to sell assets or seek financing from other sources. Sales of
+assets could further reduce the amount of our borrowing base. We cannot assure you that we would be
+successful in selling assets or arranging substitute financing. If we were not able to repay
+borrowings under our senior secured credit facility to reduce the outstanding amount to less than
+the borrowing base, we would be in default under our senior secured credit facility. For a
+description of our senior secured credit facility and its principal terms and conditions, see
+7
+Table of Contents 
+“Management’s Discussion and Analysis of Financial Condition and Results of Operations
+— Liquidity and Capital Resources” and Note 5 to our Consolidated Financial Statements.
+Our decision to drill a prospect is subject to a number of factors and we may decide to alter our
+drilling schedule or not drill at all. A prospect is a property on which we have identified what
+our geoscientists believe, based on available seismic and geological information, to be indications
+of hydrocarbons. Our prospects are in various stages of evaluation, ranging from a prospect which
+is ready to drill to a prospect which will require substantial additional seismic data processing
+and interpretation. Whether we ultimately drill a prospect may depend on the following factors:
+• 
+receipt of additional seismic data or the reprocessing of existing data; 
+• 
+material changes in oil or gas prices; 
+• 
+the costs and availability of drilling rigs; 
+• 
+the success or failure of wells drilled in similar formations or which would use the
+same production facilities; 
+• 
+availability and cost of capital; 
+• 
+changes in the estimates of the costs to drill or complete wells; 
+• 
+our ability to attract other industry partners to acquire a portion of the working
+interest to reduce exposure to costs and drilling risks; and 
+• 
+decisions of our joint working interest owners. 
+We will continue to gather data about our prospects and it is possible that additional information
+may cause us to alter our drilling schedule or determine that a prospect should not be pursued at
+all. You should understand that our plans regarding our prospects are subject to change.
+Weather, unexpected subsurface conditions, and other unforeseen operating hazards may adversely
+impact our ability to conduct business. There are many operating hazards in exploring for and
+producing oil and gas, including:
+• 
+our drilling operations may encounter unexpected formations or pressures, which could
+cause damage to equipment or personal injury; 
+• 
+we may experience equipment failures which curtail or stop production; 
+• 
+we could experience blowouts or other damages to the productive formations that may
+require a well to be re-drilled or other corrective action to be taken; and 
+• 
+because of these or other events, we could experience environmental hazards, including
+oil spills, gas leaks, and ruptures. 
+In the event of any of the foregoing, we may be subject to interrupted production or substantial
+environmental liability due to injury to or loss of life, damage to or destruction of property,
+natural resources and equipment, pollution and other environmental damage, investigation and
+remediation requirements. Moreover, a substantial portion of our operations are offshore and are
+subject to a variety of risks peculiar to the marine environment such as capsizing, collisions,
+hurricanes and other adverse weather conditions. These conditions can cause substantial damage to
+facilities and interrupt production. Offshore operations are also subject to more extensive
+governmental regulation.
+We cannot assure you that we will be able to maintain adequate insurance at rates we consider
+reasonable to cover our possible losses from operating hazards. The occurrence of a significant
+event not fully insured or indemnified against could materially and adversely affect our financial
+condition and results of operations.
+8
+Table of Contents 
+We may not have production to offset hedges; by hedging, we may not benefit from price increases. 
+Part of our business strategy is to reduce our exposure to the volatility of oil and gas prices by
+hedging a portion of our production. In a typical hedge transaction, we will have the right to
+receive from the other parties to the hedge the excess of the fixed price specified in the hedge
+over a floating price based on a market index, multiplied by the quantity hedged. If the floating
+price exceeds the fixed price, we are required to pay the other parties this difference multiplied
+by the quantity hedged. We are required to pay the difference between the floating price and the
+fixed price when the floating price exceeds the fixed price regardless of whether we have
+sufficient production to cover the quantities specified in the hedge. Significant reductions in
+production at times when the floating price exceeds the fixed price could require us to make
+payments under the hedge agreements even though such payments are not offset by sales of
+production. Hedging will also prevent us from receiving the full advantage of increases in oil or
+gas prices above the fixed amount specified in the hedge. We also enter into price “collars” to
+reduce the risk of changes in oil and gas prices. Under a collar, no payments are due by either
+party so long as the market price is above a floor set in the collar and below a ceiling. If the
+price falls below the floor, the counter-party to the collar pays the difference to us and if the
+price is above the ceiling, we pay the counter-party the difference. Another type of hedging
+contract we have entered into is a put contract. Under a put, if the price falls below the set
+floor price, the counter-party to the contract pays the difference to us. See “Quantitative and
+Qualitative Disclosures About Market Risks” for a discussion of our hedging practices.
+Compliance with environmental and other government regulations could be costly and could negatively
+impact production. Our operations are subject to numerous laws and regulations governing the
+operation and maintenance of our facilities and the discharge of materials into the environment or
+otherwise relating to environmental protection. For a discussion of the material regulations
+applicable to us, see “Regulations”. These laws and regulations may:
+• 
+require that we acquire permits before commencing drilling; 
+• 
+restrict the substances that can be released into the environment in connection with
+drilling and production activities; 
+• 
+limit or prohibit drilling activities on protected areas such as wetlands or wilderness
+areas; and 
+• 
+require remedial measures to mitigate pollution from former operations, such as
+dismantling abandoned production facilities. 
+Under these laws and regulations, we could be liable for personal injury and clean-up costs and
+other environmental and property damages, as well as administrative, civil and criminal penalties.
+We maintain limited insurance coverage for sudden and accidental environmental damages. We do not
+believe that insurance coverage for environmental damages that occur over time is available at a
+reasonable cost. Also, we do not believe that insurance coverage for the full potential liability
+that could be caused by sudden and accidental environmental damages is available at a reasonable
+cost. Accordingly, we may be subject to liability or we may be required to cease production from
+properties in the event of environmental damages.
+9
+Table of Contents 
+Factors beyond our control affect our ability to market production and our financial results. The
+ability to market oil and gas from our wells depends upon numerous factors beyond our control.
+These factors include:
+• 
+the extent of domestic production and imports of oil and gas; 
+• 
+the proximity of the gas production to gas pipelines; 
+• 
+the availability of pipeline capacity; 
+• 
+the demand for oil and gas by utilities and other end users; 
+• 
+the availability of alternative fuel sources; 
+• 
+the effects of inclement weather; 
+• 
+state and federal regulation of oil and gas marketing; and 
+• 
+federal regulation of gas sold or transported in interstate commerce. 
+Because of these factors, we may be unable to market all of the oil or gas we produce. In addition,
+we may be unable to obtain favorable prices for the oil and gas we produce.
+If oil and gas prices decrease, we may be required to take writedowns of the carrying value of our
+oil and gas properties. We may be required to writedown the carrying value of our oil and gas
+properties when oil and gas prices are low or if we have substantial downward adjustments to our
+estimated net proved reserves, increases in our estimates of development costs or deterioration in
+our exploration results. Under the full-cost method which we use to account for our oil and gas
+properties, the net capitalized costs of our oil and gas properties may not exceed the present
+value, discounted at 10%, of future net cash flows from estimated net proved reserves, using period
+end oil and gas prices or prices as of the date of our auditor’s report, plus the lower of cost or
+fair market value of our unproved properties. If net capitalized costs of our oil and gas
+properties exceed this limit, we must charge the amount of the excess to earnings. This type of
+charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity.
+We review the carrying value of our properties quarterly, based on prices in effect as of the end
+of each quarter or at the time of reporting our results. Once incurred, a writedown of oil and gas
+properties is not reversible at a later date, even if prices increase.
+There are inherent limitations in all control systems, and misstatements due to error or fraud that
+could seriously harm our business may occur and not be detected. Our management, including our
+Chief Executive and Financial Officer, does not expect that our internal controls and disclosure
+controls will prevent all possible error and all fraud. A control system, no matter how well
+conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of
+the control system are met. In addition, the design of a control system must reflect the fact that
+there are resource constraints and the benefit of controls must be relative to their costs.
+Because of the inherent limitations in all control systems, an evaluation of controls can only
+provide reasonable assurance that all material control issues and instances of fraud, if any, in
+our company have been detected. These inherent limitations include the realities that judgments in
+decision-making can be faulty and that breakdowns can occur because of simple error or mistake.
+Further, controls can be circumvented by the individual acts of some persons or by collusion of two
+or more persons. The design of any system of controls is based in part upon certain assumptions
+about the likelihood of future events, and there can be no assurance that any design will succeed
+in achieving its stated goals under all potential future conditions. Because of inherent
+limitations in a cost-effective control system, misstatements due to error or fraud may occur and
+not be detected. A failure of our controls and procedures to detect error or fraud could seriously
+harm our business and results of operations.
+10
+Table of Contents 
+Forward-Looking Statements 
+In this report, we have made many forward-looking statements. We cannot assure you that the plans,
+intentions or expectations upon which our forward-looking statements are based will occur. Our
+forward-looking statements are subject to risks, uncertainties and assumptions, including those
+discussed elsewhere in this report. Forward-looking statements include statements regarding:
+• 
+our oil and gas reserve quantities, and the discounted present value of these
+reserves; 
+• 
+the amount and nature of our capital expenditures; 
+• 
+drilling of wells; 
+• 
+the timing and amount of future production and operating costs; 
+• 
+business strategies and plans of management; and 
+• 
+prospect development and property acquisitions. 
+Some of the risks, which could affect our future results and could cause results to differ
+materially from those expressed in our forward-looking statements, include:
+• 
+general economic conditions; 
+• 
+the volatility of oil and natural gas prices; 
+• 
+the uncertainty of estimates of oil and natural gas reserves; 
+• 
+the impact of competition; 
+• 
+the availability and cost of seismic, drilling and other equipment; 
+• 
+operating hazards inherent in the exploration for and production of oil and natural
+gas; 
+• 
+difficulties encountered during the exploration for and production of oil and
+natural gas; 
+• 
+difficulties encountered in delivering oil and natural gas to commercial markets; 
+• 
+changes in customer demand and producers’ supply; 
+• 
+the uncertainty of our ability to attract capital; 
+• 
+compliance with, or the effect of changes in, the extensive governmental
+regulations regarding the oil and natural gas business; 
+• 
+actions of operators of our oil and gas properties; and 
+• 
+weather conditions. 
+The information contained in this report, including the information set forth under the heading
+“Risk Factors,” identifies additional factors that could affect our operating results and
+performance. We urge you to carefully consider these factors and the other cautionary statements in
+this report. Our forward-looking statements speak only as of the date made, and we have no
+obligation to update these forward-looking statements.
+Corporate Offices 
+Our headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned
+space. We also maintain a business office in Houston, Texas, and own or lease field offices in the
+area of the major fields in which we operate properties or have a significant interest. Replacement
+of any of our leased offices would not result in material expenditures by us as alternative
+locations to our leased space are anticipated to be readily available . 
+11
+Table of Contents 
+Employees 
+We had 87 employees as of December 31, 2005, none of whom are currently represented by a union. We
+believe that we have good relations with our employees. We employ five petroleum engineers and
+seven petroleum geoscientists.
+Regulations 
+General . The oil and gas industry is subject to regulation at the federal, state and local level,
+and some of the laws, rules and regulations that govern our operations carry substantial penalties
+for non-compliance. This regulatory burden increases our cost of doing business and, consequently,
+affects our profitability.
+Exploration and Production. Our operations are subject to federal, state and local regulations
+that include requirements for permits to drill and to conduct other operations and for provision of
+financial assurances (such as bonds) covering drilling and well operations. Other activities
+subject to regulation are:
+• 
+the location of wells, 
+• 
+the method of drilling and completing wells, 
+• 
+the rate of production, 
+• 
+the surface use and restoration of properties upon which wells are drilled, 
+• 
+the plugging and abandoning of wells, 
+• 
+the disposal of fluids used or other wastes obtained in connection with operations, 
+• 
+the marketing, transportation and reporting of production, and 
+• 
+the valuation and payment of royalties. 
+For instance, our OCS leases in federal waters are administered by the Minerals Management Service,
+or MMS, and require compliance with detailed MMS regulations and orders. Lessees must obtain MMS
+approval for exploration plans and exploitation and production plans prior to the commencement of
+such operations. The MMS has promulgated regulations requiring offshore production facilities
+located on the OCS to meet stringent engineering and construction specifications. The MMS also has
+regulations restricting the flaring or venting of natural gas, and prohibiting the flaring of
+liquid hydrocarbons and oil without prior authorization. MMS policies concerning the volume of
+production that a lessee must have to maintain an offshore lease beyond its primary term also are
+applicable to Callon. Similarly, the MMS has promulgated other regulations governing the plugging
+and abandonment of wells located offshore and the installation and removal of all production
+facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires
+that lessees have substantial net worth or post bonds or other acceptable assurances that such
+obligations will be met. The cost of these bonds or other surety can be substantial, and there is
+no assurance that bonds or other surety can be obtained in all cases. Under some circumstances,
+the MMS may require any of our operations on federal leases to be suspended or terminated. Any
+such suspension or termination could materially adversely affect our financial conditions and
+results of operations.
+Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline
+transportation. The price and terms for access to pipeline transportation remain subject to
+extensive federal regulation. If these regulations change, we could face higher transmission costs
+for our production and, possibly, reduced access to transmission capacity.
+12
+Table of Contents 
+We do not currently anticipate that compliance with existing laws and regulations governing
+exploration and production will have a significantly adverse effect upon our capital expenditures,
+earnings or competitive position.
+Various proposals and proceedings that might affect the petroleum industry are pending before
+Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the
+courts. The industry historically has been heavily regulated and we can offer you no assurance
+that the less stringent regulatory approach recently pursued by the FERC and Congress will continue
+nor can we predict what effect such proposals or proceedings may have on our operations.
+Environmental Regulation. Various federal, state and local laws and regulations concerning the
+discharge of contaminants into the environment, the generation, storage, transportation and
+disposal of contaminants, and the protection of public health, natural resources, wildlife and the
+environment affect our exploration, development and production operations, including processing
+facilities. We must take into account the cost of complying with environmental regulations in
+planning, designing, drilling, constructing, operating and abandoning wells. In most instances, the
+regulatory requirements relate to the handling and disposal of drilling and production waste
+products, water and air pollution control procedures, and the remediation of petroleum-product
+contamination. In addition, our operations may require us to obtain permits for, among other
+things,
+• 
+air emissions, 
+• 
+discharges into surface waters, and 
+• 
+the construction and operations of underground injection wells or surface pits to
+dispose of produced saltwater and other nonhazardous oilfield wastes. 
+In the event of an unauthorized discharge, emission or activity, we may be liable for penalties,
+costs and damages. Under state and federal laws, we could be required to remove or remediate
+previously disposed wastes and remediate contamination, including contamination in surface water,
+soil or groundwater, caused by disposal of that waste. We could be responsible for wastes disposed
+of or released by us or prior owners or operators at properties owned or leased by us or at
+locations where wastes have been taken for disposal. We could also be required to suspend or cease
+operations in contaminated areas, or to perform remedial well plugging operations or cleanups to
+prevent future contamination. The Environmental Protection Agency and various state agencies have
+limited the disposal options for hazardous and nonhazardous wastes. The owner and operator of a
+site, and persons that treated, disposed of or arranged for the disposal of hazardous substances
+found at a site, may be liable, without regard to fault or the legality of the original conduct,
+for the release of a hazardous substance into the environment. The Environmental Protection Agency,
+state environmental agencies and, in some cases, third parties are authorized to take actions in
+response to threats to human health or the environment and to seek to recover from responsible
+classes of persons the costs of such action. Furthermore, certain wastes generated by our oil and
+natural gas operations that are currently exempt from treatment as hazardous wastes may in the
+future be designated as hazardous wastes and, therefore, be subject to considerably more rigorous
+and costly operating and disposal requirements.
+Federal and state occupational safety and health laws require us to organize information about
+hazardous materials used, released or produced in our operations. Certain portions of this
+information must be provided to employees, state and local governmental authorities and local
+citizens. We are also subject to the requirements and reporting set forth in federal workplace
+standards.
+We have made and will continue to make expenditures to comply with environmental regulations and
+requirements. These are necessary business costs in the oil and gas industry. Although we are not
+fully
+13
+Table of Contents 
+insured against all environmental risks, we maintain insurance coverage which we believe is
+customary in the industry. Moreover, it is possible that other developments, such as stricter and
+more comprehensive environmental laws and regulations, as well as claims for damages to property or
+persons resulting from company operations, could result in substantial costs and liabilities,
+including civil and criminal penalties, to Callon. We believe we are in compliance with existing
+environmental regulations, and that, absent the occurrence of an extraordinary event the effect of
+which cannot be predicted, any noncompliance will not have a material adverse effect on our
+operations or earnings.
+Commitments and Contingencies 
+The Company’s activities are subject to federal, state and local laws and regulations governing
+environmental quality and pollution control. Although no assurances can be made, the Company
+believes that, absent the occurrence of an extraordinary event, compliance with existing federal,
+state and local laws, rules and regulating the release of materials in the environment or otherwise
+relating to the protection of the environment will not have a material effect upon the capital
+expenditures, earnings or the competitive position of the Company with respect to its existing
+assets and operations. The Company cannot predict what effect additional regulation or
+legislation, enforcement polices thereunder, and claims for damages to property, employees, other
+person, and the environment resulting from the Company’s operations could have on its activities.
+Property Summary 
+We are engaged in the exploration, development, acquisition and production of oil and gas
+properties. Our properties are concentrated offshore in the Gulf of Mexico and onshore, primarily,
+in Louisiana and Alabama. We have historically increased our reserves and production by focusing
+primarily on low to moderate risk exploration and acquisition opportunities in the Gulf of Mexico
+shelf area. In 1998, we expanded our area of exploration to include the Gulf of Mexico deepwater
+area. As of December 31, 2005, our estimated net proved reserves totaled 188.6 Bcfe and included
+18.4 million barrels of oil (“MMBbl”) and 78.0 billion cubic feet of natural gas (“Bcf”), with a
+pre-tax present value, discounted at 10%, of the estimated future net revenues based on constant
+prices in effect at year-end of $1.1 billion. Oil constitutes approximately 59% on an equivalent
+basis of our total estimated proved reserves and approximately 40% of our total estimated proved
+reserves are proved developed reserves.
+Our Medusa (Mississippi Canyon Blocks 538/582) and Habanero (Garden Banks Block 341) discoveries
+began production in the fourth quarter of 2003. A detailed discussion of each of these properties
+is provided in the “Significant Properties” section of this report. These two deepwater discoveries
+were responsible for 62% of our total production during 2005.
+14
+Table of Contents 
+Significant Properties 
+The following table shows discounted cash flows and estimated net proved oil and gas reserves by
+major field and for all other properties combined at December 31, 2005.
+Pre-tax 
+Estimated Net Proved Reserves 
+Discounted 
+Oil 
+Gas 
+Total 
+Present Value 
+Operator 
+(MBbls) 
+(MMcf) 
+(MMcfe) 
+($000) 
+(a)(b) 
+Gulf of Mexico Deepwater: 
+Garden Banks Block
+738/782/826/827
+“Entrada” 
+BP 
+7,772 
+29,126 
+75,760 
+$ 
+409,904 
+Mississippi Canyon 538/582
+“Medusa” 
+Murphy 
+6,566 
+4,814 
+44,208 
+255,386 
+Garden Banks Block 341
+“Habanero” 
+Shell 
+2,886 
+6,730 
+24,047 
+150,678 
+Gulf of Mexico Shelf: 
+West Cameron Block 295 
+HydroGOM/Cimarex 
+— 
+8,217 
+8,217 
+58,401 
+High Island Block A-540 
+Walter 
+106 
+3,305 
+3,939 
+24,127 
+Mobile Blocks 953/955 
+Callon 
+— 
+4,216 
+4,216 
+24,201 
+Mobile Block 864 Unit 
+Callon 
+— 
+3,517 
+3,517 
+19,008 
+North Padre Island Block 913 
+Callon 
+2 
+3,457 
+3,467 
+29,381 
+East Cameron Block 90 
+Callon 
+— 
+2,255 
+2,256 
+19,487 
+High Island Block 119 
+Kerr-McGee 
+25 
+1,822 
+1,970 
+14,803 
+Other 
+Various 
+70 
+4,107 
+4,530 
+19,319 
+Onshore and Other: 
+Alabama 
+Various 
+513 
+1,288 
+4,365 
+18,121 
+Louisiana 
+Various 
+356 
+4,714 
+6,848 
+38,335 
+Other States 
+Various 
+132 
+453 
+1,248 
+7,566 
+Total Net Proved Reserves 
+18,428 
+78,021 
+188,588 
+$ 
+1,088,714 
+(a) 
+Represents the present value of future net cash flows before deduction of federal income
+taxes, discounted at 10%, attributable to estimated net proved reserves as of December 31,
+2005, as set forth in the Company’s reserve reports prepared by its independent petroleum
+reserve engineers, Huddleston & Co., Inc. of Houston, Texas. 
+(b) 
+Includes a reduction for estimated plugging and abandonment costs that is reflected as a
+liability on our balance sheet at December 31, 2005, in accordance with Statement of Financial
+Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). See
+the Oil and Gas Reserve table for the standardized measure of discounted future net cash flow
+which is a required calculation by the SEC. 
+15
+Table of Contents 
+Gulf of Mexico Deepwater 
+Entrada, Garden Banks Blocks 738/782/826/827 
+The Entrada discovery is located in approximately 4,500 feet of water in the Gulf of Mexico. Two
+wells and seven sidetracks have been drilled to date. The Entrada Area is characterized by a
+northwest plunging salt ridge with multiple stacked amplitudes trapped against the salt and various
+faults. We own a 20% working interest in this discovery with BP, the operator, holding the
+remaining working interest.
+An integrated project team consisting of personnel from BP and Callon, along with Conoco-Phillips
+and Devon Energy Corporation, the owners of production facilities in
+nearby Garden Banks 783, are working on a front-end engineering design study to tie-back
+Entrada to the production facilities. Project sanction is targeted for the
+second half of 2006 with first production expected in 2008.
+Medusa, Mississippi Canyon Blocks 538/582 
+Our Medusa deepwater discovery was announced in September 1999, after we drilled the initial test
+well in 2,235 feet of water to a total depth of 16,241 feet and encountered over 120 feet of pay in
+two intervals. Subsequent sidetrack drilling from the wellbore was used to determine the extent of
+the discovery and a second well was drilled in the first quarter of 2000 to further delineate the
+extent of the pay intervals. We own a 15% working interest, Murphy Exploration & Production Company
+(“Murphy”), the operator, owns a 60% working interest and ENI Deepwater, LLC, owns the remaining
+25% working interest.
+In 2001 a drilling program began which included four development wells and one sidetrack. The
+program included production casing being set on six wells to provide initial production take-points
+and was completed in the first half of 2002. The construction of a floating production system,
+spar, at Medusa was completed during the second quarter of 2003. The A-1 well was completed and
+tied into the spar and commenced production in late November 2003. The remaining five wells were
+completed and commenced production in 2004. Mississippi Canyon 538 #4, North Medusa, was drilled
+in 2003 and was temporarily abandoned after encountering 28 feet of net pay. The well bore was
+re-entered in the fourth quarter of 2004, sidetracked and reached an objective depth of 9,600 feet
+in January 2005. The sidetrack encountered 46 feet of net pay, was completed and commenced initial
+production in April 2005 at a gross rate of 5,000 barrels of oil equivalent per day.
+During 2005 the field produced 8.1 Bcfe net to us which accounted for 43% of our total production.
+Due to hurricanes and tropical storms during 2005, Medusa was not productive for approximately 102
+days. After repairs of damage to Medusa’s facilities and third-party transmission lines and
+production facilities caused by Hurricane Katrina, production was restored in November 2005 and
+pre-hurricane rates were achieved during December 2005. Medusa produced at an average daily gross
+rate of 34,000 barrels of crude oil and 35 MMcf during January 2006.
+In December 2003, we transferred our undivided 15% working interest in the spar production
+facilities to Medusa Spar LLC in exchange for cash proceeds of approximately $25 million and a 10%
+ownership interest in the LLC. A detailed discussion of this transaction is included in
+Management’s Discussion and Analysis of Financial Condition and Results of Operations-“Off-Balance
+Sheet Arrangements”.
+Habanero, Garden Banks Block 341 
+During February 1999, the initial test well on our Habanero deepwater discovery encountered over
+200 feet of net pay in two zones. Located in 2,000 feet of water, the well was drilled to a
+measured depth of
+16
+Table of Contents 
+21,158 feet. We own an 11.25% working interest in the well. The well is operated
+by Shell Deepwater Development Inc., which owns a 55% working interest, with the remaining working
+interest being owned by Murphy.
+A field delineation program began in mid-year 2001, which included three sidetracks of the
+discovery well. Production casing was set on this well through one of the sidetracks to the
+Habanero 52 oil and gas sand and the Habanero 55 gas sand. Also, a development well was drilled in
+the summer of 2003 which provides a take-point for production from the Habanero 52 oil sand. By
+means of a sub-sea completion and tie back to an existing production facility in the area operated
+by Shell, production from the Habanero 52 oil sand commenced in late November 2003 and from the
+Habanero 55 gas sand in January 2004. In July 2004 the #2 well producing the Habanero 52 oil sand
+developed mechanical difficulties with a subsurface control value and was shut-in resulting in a
+significant loss of production. Repairs were completed and production was restored in late
+December 2004. In addition, the #1 well producing the Habanero 55 gas sand was recompleted to the
+Habanero 55 oil sand in December 2004.
+During 2005 Habanero produced 3.5 Bcfe net to us which accounted for 19% of our total production.
+Due to hurricanes and tropical storms during 2005 the field was not productive for approximately 85
+days. After repairs of damage primarily to third-party transmission lines and production facilities
+caused by Hurricane Rita, production was restored in November 2005 and pre-hurricane rates were
+achieved during December 2005. Habanero produced at an average daily gross rate of 12,000 barrels
+of crude oil and 17 MMcf during January 2006.
+Gulf of Mexico Shelf 
+West Cameron Block 295 
+During the third quarter of 2005, the #2 well reached a total depth of 15,775 feet and logged 150
+feet of net pay in two zones. Each zone was encountered at the predicted depth and exceeded
+anticipated thickness. First production from the #2 well is expected in the first half of March
+2006 at a gross rate of approximately 30 MMcf per day. Callon holds a 20.5% working interest in
+the block and Hydro Gulf of Mexico, LLC is the operator.
+A second prospect on this block was also drilled during 2005. The #3 well was drilled to a depth
+of 16,286 feet in December 2005 and logged 110 feet of net (94 feet true vertical depth) pay in two
+zones. Production is expected to commence during May 2006 at a gross rate of approximately 10 MMcf
+per day. Callon holds a 20.5% working interest in the block and Cimarex Energy Company is the
+operator.
+High Island Block A-540 
+The #1 well was spud in November 2005 and reached a total depth of 9,450 feet the following month
+after logging 32 feet of net pay in the objective section. First production is scheduled to
+commence in July 2006 at an anticipated gross rate of approximately 11 MMcfe per day. The company
+owns a 60% working interest and Walter Oil and Gas is the operator.
+Mobile Blocks 953/955 
+We own a 100% working interest in these two blocks and we are the operator. In the fourth quarter
+of 2001, we initiated a production acceleration program for Mobile Blocks 952, 953 and 955, which
+were being produced through the Mobile Block 864 Unit facilities and were production constrained.
+An
+17
+Table of Contents 
+acceleration well was successfully drilled in the fourth quarter of 2001 and stand-alone
+production facilities were installed and production flow lines were rerouted to the new facilities.
+Production commenced through the new facilities in April 2002. In order to completely produce the
+proved reserves of the field we drilled a development well on Mobile Block 955 during the first
+quarter of 2004.
+During 2005 the three wells on the blocks produced 2.5 Bcf of natural gas net to us which accounted
+for 13.2% of our total production. Due to hurricanes and tropical storms during 2005, two of the
+wells were not productive for approximately 48 days and one well was down for 136 days. After
+repairs of damages caused by Hurricane Katrina, the field produced at an average daily gross rate
+of 7 MMcf during January 2006.
+Mobile Block 864 Unit 
+We operate the Mobile Block 864 Unit, in which we have a 66.4% working interest. The Unit has four
+producing wells, unit production facilities and covers portions of three blocks.
+During 2005 the Unit produced 833 MMcf of natural gas net to us which accounted for 4.4% of our
+total production. Due to hurricanes and tropical storms during 2005, the Unit was not productive
+for approximately 48 days. After repairs of damages caused by Hurricane Katrina, production was
+restored in November 2005. The field produced at an average daily gross rate of 4 MMcf during
+January 2006.
+North Padre Island Block 913 
+An exploratory well was drilled to a vertical depth of 8,082 feet in the fourth quarter of 2004 and
+found natural gas pay in multiple intervals. Currently, the well is being tied back to existing
+infrastructure on a nearby block. We are the operator and own a 50% working interest. First
+production is expected to commence in March 2006 at a gross rate of 15 MMcfe per day. The initial
+production was delayed due to equipment availability problems caused by Hurricanes Katrina and
+Rita.
+East Cameron Block 90 
+The #1 well reached total depth of 8,500 feet in January 2005 and encountered 42 feet of net pay at
+two intervals, including 34 feet in the primary objective. The well commenced initial production
+in December 2005 at a gross rate of 5 MMcf per day. Callon operates and owns a 61.7% working
+interest. The initial production was delayed due to equipment availability problems caused by
+Hurricanes Katrina and Rita.
+High Island Block 119 
+An initial exploratory well and one development well were drilled and completed in 2004. First
+production began in the third quarter of 2004. An exploratory well in an offsetting fault block
+was spud late in the fourth quarter of 2004 and was completed in 2005. We own a 22% working
+interest and Kerr- McGee Oil and Gas Corporation is the operator.
+These three wells produced 1.2 Bcfe of natural gas net to our interest during 2005 which accounted
+for 6.5% of our total production. Due to hurricanes and tropical storms during 2005, the field was
+not productive for approximately 102 days. After repairs of damages caused by Hurricane Rita,
+production was restored in January 2006. The field is currently producing at an average daily
+gross rate of 13.0 MMcfe.
+18
+Table of Contents 
+Oil and Gas Reserves 
+The following table sets forth certain information about our estimated proved reserves as reported
+by Huddleston & Co., Inc. as of the dates set forth below.
+Years Ended December 31, 
+2005 
+2004 
+2003 
+(In thousands) 
+Proved developed: 
+Oil (Bbls) 
+7,323 
+10,292 
+9,919 
+Gas (Mcf) 
+30,982 
+33,982 
+31,415 
+Mcfe 
+74,921 
+95,735 
+90,926 
+Proved undeveloped: 
+Oil (Bbls) 
+11,105 
+9,456 
+13,790 
+Gas (Mcf) 
+47,039 
+38,637 
+43,276 
+Mcfe 
+113,667 
+95,373 
+126,017 
+Total proved: 
+Oil (Bbls) 
+18,428 
+19,748 
+23,709 
+Gas (Mcf) 
+78,021 
+72,619 
+74,691 
+Mcfe 
+188,588 
+191,108 
+216,943 
+Estimated pre-tax future net cash flows (a) 
+$ 
+1,487,817 
+$ 
+892,145 
+$ 
+838,847 
+Pre-tax discounted present value (a) 
+$ 
+1,088,714 
+$ 
+612,595 
+$ 
+570,463 
+Standardized measure of discounted future
+net cash flows(a) 
+$ 
+837,552 
+$ 
+515,893 
+$ 
+519,026 
+(a) 
+Includes a reduction for estimated plugging and abandonment costs that is reflected as
+a liability on our balance sheet at December 31, 2005, in accordance with SFAS 143. 
+Our independent reserve engineers, Huddleston & Co., Inc., prepared the estimates of the proved
+reserves and the future net cash flows and present value thereof attributable to such proved
+reserves. Reserves were estimated using oil and gas prices and production and development costs in
+effect on December 31 of each
+19
+Table of Contents 
+such year, without escalation, and were otherwise prepared in
+accordance with SEC regulations regarding disclosure of oil and gas reserve information.
+There are numerous uncertainties inherent in estimating quantities of proved reserves, including
+many factors beyond our control or the control of the reserve engineers. Reserve engineering is a
+subjective process of estimating underground accumulations of oil and gas that cannot be measured
+in an exact manner. The accuracy of any reserve or cash flow estimate is a function of the quality
+of available data and of engineering and geological interpretation and judgment. Estimates by
+different engineers often vary, sometimes significantly. In addition, physical factors, such as
+the results of drilling, testing and production subsequent to the date of an estimate, as well as
+economic factors, such as an increase or decrease in product prices that renders production of such
+reserves more or less economic, may justify revision of such estimates. Accordingly, reserve
+estimates could be different from the quantities of oil and gas that are ultimately recovered.
+We have not filed any reports with other federal agencies which contain an estimate of total proved
+net oil and gas reserves during our last fiscal year.
+Present Activities and Productive Wells 
+The following table sets forth the wells we have drilled and completed during the periods
+indicated. All such wells were drilled in the continental United States primarily in federal and
+state waters in the Gulf of Mexico.
+Years Ended December 31, 
+2005 
+2004 
+2003 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development: 
+Oil 
+1 
+0.15 
+— 
+— 
+2 
+.23 
+Gas 
+— 
+— 
+2 
+1.22 
+— 
+— 
+Non-productive 
+— 
+— 
+— 
+— 
+— 
+— 
+Total 
+1 
+0.15 
+2 
+1.22 
+2 
+.23 
+Exploration: 
+Oil 
+— 
+— 
+— 
+— 
+1 
+.15 
+Gas 
+7 
+2.42 
+2 
+.72 
+— 
+— 
+Non-productive 
+4 
+1.25 
+5 
+1.24 
+1 
+.20 
+Total 
+11 
+3.67 
+7 
+1.96 
+2 
+.35 
+20
+Table of Contents 
+The following table sets forth our productive wells as of December 31, 2005:
+Wells 
+Gross 
+Net 
+Oil: 
+Working interest 
+39.00 
+3.75 
+Royalty interest 
+192.00 
+3.14 
+Total 
+231.00 
+6.89 
+Gas: 
+Working interest 
+33.00 
+12.70 
+Royalty interest 
+209.00 
+1.58 
+Total 
+242.00 
+14.28 
+A well is categorized as an oil well or a natural gas well based upon the ratio of oil to gas
+reserves on a Mcfe basis. However, some of our wells produce both oil and gas. At December 31,
+2005, we had no wells with multiple completions. At December 31, 2005, 1 gross (0.033 net)
+exploration oil well and 1 gross (0.205 net) exploration gas well were in progress.
+Leasehold Acreage 
+The following table shows our approximate developed and undeveloped (gross and net) leasehold
+acreage as of December 31, 2005.
+Leasehold Acreage 
+Developed 
+Undeveloped 
+Location 
+Gross 
+Net 
+Gross 
+Net 
+Louisiana 
+6,092 
+3,882 
+13,516 
+5,584 
+Texas 
+78 
+— 
+15,870 
+6,680 
+Other states 
+— 
+— 
+681 
+509 
+Federal waters 
+108,102 
+56,770 
+257,140 
+78,523 
+Total 
+114,272 
+60,652 
+287,207 
+91,296 
+As of December 31, 2005, we owned various royalty and overriding royalty interests in 1,336 net
+developed and 6,862 net undeveloped acres. In addition, we owned 4,309 developed and 121,691
+undeveloped mineral acres.
+Major Customers 
+Our production is sold generally on month-to-month contracts at prevailing prices. The following
+table identifies customers to whom we sold a significant percentage of our total oil and gas
+production during each of the 12-month periods ended:
+21
+Table of Contents 
+December 31, 
+2005 
+2004 
+2003 
+Shell Trading Company 
+34 
+% 
+30 
+% 
+— 
+Louis Dreyfus Energy Services 
+16 
+% 
+23 
+% 
+27 
+% 
+Plains Marketing, L.P. 
+16 
+% 
+13 
+% 
+— 
+Chevron Texaco Natural Gas 
+10 
+% 
+6 
+% 
+— 
+Reliant Energy Services 
+— 
+6 
+% 
+28 
+% 
+Prior Energy Corporation 
+— 
+— 
+20 
+% 
+Because alternative purchasers of oil and gas are readily available, we believe that the loss of
+any of these purchasers would not result in a material adverse effect on our ability to market
+future oil and gas production.
+Title to Properties 
+We believe that the title to our oil and gas properties is good and defensible in accordance with
+standards generally accepted in the oil and gas industry, subject to such exceptions which, in our
+opinion, are not so material as to detract substantially from the use or value of such properties.
+Our properties are typically subject, in one degree or another, to one or more of the following:
+• 
+royalties and other burdens and obligations, express or implied, under oil and gas leases; 
+• 
+overriding royalties and other burdens created by us or our predecessors in title; 
+• 
+a variety of contractual obligations (including, in some cases, development obligations)
+arising under operating agreements, farmout agreements, production sales contracts and
+other agreements that may affect the properties or their titles; 
+• 
+back-ins and reversionary interests existing under purchase agreements and leasehold
+assignments; 
+• 
+liens that arise in the normal course of operations, such as those for unpaid taxes,
+statutory liens securing obligations to unpaid suppliers and contractors and contractual
+liens under operating agreements; 
+• 
+pooling, unitization and communitization agreements, declarations and orders; and 
+• 
+easements, restrictions, rights-of-way and other matters that commonly affect property. 
+To the extent that such burdens and obligations affect our rights to production revenues, they have
+been taken into account in calculating our net revenue interests and in estimating the size and
+value of our reserves. We believe that the burdens and obligations affecting our properties are
+conventional in the industry for properties of the kind owned by us.
+22
+Table of Contents 
+ITEM 3. LEGAL PROCEEDINGS 
+We are a defendant in various legal proceedings and claims, which arise in the ordinary course of
+our business. We do not believe the ultimate resolution of any such actions will have a material
+affect on our financial position or results of operations.
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 
+There were no matters submitted to a vote of security holders during the fourth quarter of 2005.
+23
+Table of Contents 
+PART II. 
+ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS 
+Our common stock trades on the New York Stock Exchange under the symbol “CPE”. The following table
+sets forth the high and low sale prices per share as reported for the periods indicated.
+Quarter Ended 
+High 
+Low 
+2004: 
+First quarter 
+$ 
+11.23 
+$ 
+8.70 
+Second quarter 
+14.27 
+10.15 
+Third quarter 
+14.40 
+11.10 
+Fourth quarter 
+14.72 
+12.30 
+2005: 
+First quarter 
+$ 
+18.00 
+$ 
+13.22 
+Second quarter 
+16.12 
+12.42 
+Third quarter 
+21.25 
+14.81 
+Fourth quarter 
+22.29 
+16.65 
+As of March 2, 2006, there were approximately 4,179 common stockholders of record.
+We have never paid dividends on our common stock and intend to retain our cash flow from
+operations, net of preferred stock dividends, for the future operation and development of our
+business. In addition, our primary credit facility and the terms of our outstanding subordinated
+debt prohibit the payment of cash dividends on our common stock.
+ITEM 6. SELECTED FINANCIAL DATA 
+The following table sets forth, as of the dates and for the periods indicated, selected financial
+information about us. The financial information for each of the five years in the period ended
+December 31, 2005 has been derived from our audited Consolidated Financial Statements for such
+periods. The information should be read in conjunction with “Management’s Discussion and Analysis
+of Financial Condition and Results of Operations” and the Consolidated Financial Statements and
+Notes thereto. The following information is not necessarily indicative of our future results.
+24
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+SELECTED HISTORICAL FINANCIAL INFORMATION 
+(In thousands, except per share amounts) 
+Years Ended December 31, 
+2005 
+2004 
+2003 
+2002 
+2001 
+Statement of Operations Data: 
+Operating revenues: 
+Oil and gas sales 
+$ 
+141,290 
+$ 
+119,802 
+$ 
+73,697 
+$ 
+61,171 
+$ 
+60,010 
+Operating expenses: 
+Lease operating expenses 
+24,377 
+22,308 
+11,301 
+11,030 
+11,252 
+Depreciation, depletion and amortization 
+44,946 
+47,453 
+28,253 
+27,096 
+21,081 
+General and administrative 
+8,085 
+8,758 
+4,713 
+4,705 
+4,635 
+Accretion expense 
+3,549 
+3,400 
+2,884 
+— 
+— 
+Derivative expense 
+6,028 
+1,371 
+535 
+708 
+— 
+Total operating expenses 
+86,985 
+83,290 
+47,686 
+43,539 
+36,968 
+Income from operations 
+54,305 
+36,512 
+26,011 
+17,632 
+23,042 
+Other (income) expenses: 
+Interest expense 
+16,660 
+20,137 
+30,614 
+26,140 
+12,805 
+Other (income) 
+(998 
+) 
+(357 
+) 
+(444 
+) 
+(1,004 
+) 
+(1,742 
+) 
+Loss on early extinguishment of debt 
+— 
+3,004 
+5,573 
+— 
+— 
+Gain on sale of pipeline 
+— 
+— 
+— 
+(2,454 
+) 
+— 
+Gain on sale of Enron derivatives 
+— 
+— 
+— 
+(2,479 
+) 
+— 
+Writedown of Enron derivatives 
+— 
+— 
+— 
+— 
+9,186 
+Total other (income) expenses 
+15,662 
+22,784 
+35,743 
+20,203 
+20,249 
+Income (loss) before income taxes 
+38,643 
+13,728 
+(9,732 
+) 
+(2,571 
+) 
+2,793 
+Income tax expense (benefit) 
+13,209 
+(6,697 
+) 
+8,432 
+(900 
+) 
+977 
+Income (loss) before Medusa Spar LLC and
+cumulative effect of change in accounting principle 
+25,434 
+20,425 
+(18,164 
+) 
+(1,671 
+) 
+1,816 
+Income (loss) on Medusa Spar LLC, net of tax 
+1,342 
+1,076 
+(8 
+) 
+— 
+— 
+Income (loss) before cumulative effect of change in
+in accounting principle 
+26,776 
+21,501 
+(18,172 
+) 
+(1,671 
+) 
+1,816 
+Cumulative effect of change in accounting principle,
+net of tax 
+— 
+— 
+181 
+— 
+— 
+Net income (loss) 
+26,776 
+21,501 
+(17,991 
+) 
+(1,671 
+) 
+1,816 
+Preferred stock dividends 
+318 
+1,272 
+1,277 
+1,277 
+1,277 
+Net income (loss) available to common shares 
+$ 
+26,458 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+$ 
+(2,948 
+) 
+$ 
+539 
+25
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+SELECTED HISTORICAL FINANCIAL INFORMATION 
+(In thousands, except per share amounts) 
+Years Ended December 31, 
+2005 
+2004 
+2003 
+2002 
+2001 
+Net income (loss) available to common shares 
+$ 
+26,458 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+$ 
+(2,948 
+) 
+$ 
+539 
+Net income (loss) per common share: 
+Basic: 
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+1.43 
+$ 
+1.28 
+$ 
+(1.42 
+) 
+$ 
+(.22 
+) 
+$ 
+.04 
+Cumulative effect of change in accounting principle,
+net of tax 
+— 
+— 
+.01 
+— 
+— 
+Net income (loss) available to common 
+$ 
+1.43 
+$ 
+1.28 
+$ 
+(1.41 
+) 
+$ 
+(.22 
+) 
+$ 
+.04 
+Diluted: 
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+1.28 
+$ 
+1.22 
+$ 
+(1.42 
+) 
+$ 
+(.22 
+) 
+$ 
+.04 
+Cumulative effect of change in accounting principle,
+net of tax 
+— 
+— 
+.01 
+— 
+— 
+Net income (loss) available to common 
+$ 
+1.28 
+$ 
+1.22 
+$ 
+(1.41 
+) 
+$ 
+(.22 
+) 
+$ 
+.04 
+Shares used in computing net income (loss) per common share: 
+Basic 
+18,453 
+15,796 
+13,662 
+13,387 
+13,273 
+Diluted 
+20,883 
+17,678 
+13,662 
+13,387 
+13,366 
+Balance Sheet Data (end of period): 
+Oil and gas properties, net 
+$ 
+447,364 
+$ 
+406,690 
+$ 
+390,163 
+$ 
+377,661 
+$ 
+343,158 
+Total assets 
+$ 
+533,776 
+$ 
+457,523 
+$ 
+496,032 
+$ 
+410,613 
+$ 
+372,095 
+Long-term debt, less current portion 
+$ 
+188,813 
+$ 
+192,351 
+$ 
+214,885 
+$ 
+248,269 
+$ 
+161,733 
+Stockholders’ equity 
+$ 
+228,048 
+$ 
+198,312 
+$ 
+133,261 
+$ 
+140,960 
+$ 
+147,224 
+We use the full-cost method of accounting. Under this method of accounting, our net
+capitalized costs to acquire explore and develop oil and gas properties may not exceed the
+standardized measure of our proved reserves. If these capitalized costs exceed a ceiling amount,
+the excess is charged to expense.
+26
+Table of Contents 
+ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+The following discussion is intended to assist in an understanding of our financial condition and
+results of operations. Our Consolidated Financial Statements and Notes thereto contain detailed
+information that should be referred to in conjunction with the following discussion. See Item 8.
+“Financial Statements and Supplementary Data.”
+General 
+We have been engaged in the exploration, development, acquisition and production of oil and gas
+properties since 1950. Our revenues, profitability and future growth and the carrying value of our
+oil and gas properties are substantially dependent on prevailing prices of oil and gas and our
+ability to find, develop and acquire additional oil and gas reserves that are economically
+recoverable. Our ability to maintain or increase our borrowing capacity and to obtain additional
+capital on attractive terms is also influenced by oil and gas prices.
+Significant events of our financial and operating results for the year ended December 31, 2005
+included an increase in the borrowing base from $60 million to $70 million, production downtime in
+the third and fourth quarter associated with the tropical storm activity and the redemption of all
+our outstanding shares of $2.125 Convertible Exchange Preferred Stock, Series A. As a result of
+the redemption, we will benefit from an annual cash savings of $1.3 million in dividend payments.
+We expect that planned 2006 capital expenditures of approximately $125 million will be funded with
+cash flows from operations and supplemented, if necessary, with our senior secured credit facility
+which had $62.5 million available on December 31, 2005. For a more detailed discussion of
+outstanding debt see Note 5 to our Consolidated Financial Statements.
+Our estimated net proved oil and gas reserves decreased at December 31, 2005 to 188.6 Bcfe. This
+represents a decrease of 1% from previous year-end 2004 estimated proved reserves of 191.1 Bcfe.
+We produced 18.8 Mmcfe and had net reserve additions of 16.3 Mmcfe.
+Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in
+the supply of and demand for oil and gas, market uncertainty and a variety of additional factors
+beyond our control. These factors include weather conditions in the United States, the condition
+of the United States economy, the actions of the Organization of Petroleum Exporting Countries,
+governmental regulation, political stability in the Middle East and elsewhere, the foreign supply
+of crude oil and natural gas, the price of foreign imports and the availability of alternate fuel
+sources. Any substantial and extended decline in the price of crude oil or natural gas would have
+an adverse effect on our carrying value of our proved reserves, borrowing capacity, revenues,
+profitability and cash flows from operations. We use derivative financial instruments (see Note 6
+to our Consolidated Financial Statements and Item 7A. “Quantitative and Qualitative Disclosures
+About Market Risks”) for price protection purposes on a limited amount of our future production and
+do not use them for trading purposes. On a Mcfe basis, natural gas represents approximately 58% of
+the budgeted 2006 production and 41% of proved reserves at year-end 2005.
+Inflation has not had a material impact on us and is not expected to have a material impact on us
+in the future.
+27
+Table of Contents 
+Summary of Significant Accounting Policies 
+On December 16, 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised
+2004), Share-Based Payment (“SFAS 123R”), which is a revision of Statement of Financial Accounting
+Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”). SFAS 123R supersedes
+APB Opinion No. 25, “Accounting for Stock Issued to Employees”, and amends Statement of Financial
+Accounting Standards No. 95, “Statement of Cash Flows”. Generally, the approach in SFAS 123R is
+similar to the approach described in SFAS 123. However, SFAS 123R requires all share-based
+payments to employees, including grants of employee stock options, to be recognized in the income
+statement based on their fair values. Pro forma disclosure is no longer an alternative.
+In April 2005, the SEC delayed the effective date of SFAS 123R for public companies to no later
+than the beginning of the first fiscal year beginning after June 15, 2005. Early adoption will be
+permitted in periods in which financial statements have not yet been issued. SFAS 123R permits
+public companies to adopt its requirements using one of two methods below:
+• 
+A “modified prospective” method in which compensation cost is recognized beginning with
+the effective date (a) based on the requirements of SFAS 123R for all share-based payments
+granted after the effective date and (b) based on the requirements of SFAS 123 for all
+awards granted to employees prior to the effective date of SFAS 123R that remain unvested
+on the effective date; or 
+• 
+A “modified retrospective” method which includes the requirements of the modified
+prospective method described above, but also permits entities to restate based on the
+amounts previously recognized under SFAS 123 for purposes of pro forma disclosures either
+(a) all prior periods presented or (b) prior interim periods of the year of adoption. 
+As permitted by SFAS 123, we currently account for share-based payments to employees using APB
+Opinion 25’s intrinsic value method and, as such, generally recognize no compensation cost for
+employee stock options. Accordingly, the adoption of SFAS 123R’s fair value method could have a
+significant impact on our result of operations, although it will have no impact on our overall
+financial position. The impact of adoption of SFAS 123R cannot be predicted at this time because
+it will depend on levels of share-based payments granted in the future. However, had we adopted
+SFAS 123R in prior periods, the impact of that standard would have approximated the impact of SFAS
+123 as described in the disclosure of pro forma net income and earnings per share in Note 2 to our
+Consolidated Financial Statements. We adopted SFAS 123R on January 1, 2006 using the modified
+prospective method.
+Property and Equipment. We follow the full-cost method of accounting for oil and gas properties
+whereby all costs incurred in connection with the acquisition, exploration and development of oil
+and gas reserves, including certain overhead costs, are capitalized into the “full-cost pool.” The
+amounts we capitalize into the full-cost pool are depleted (charged against earnings) using the
+unit-of-production method. The full-cost method of accounting for our proved oil and gas
+properties requires that we make estimates based on assumptions as to future events which could
+change. These estimates are described below.
+28
+Table of Contents 
+Depreciation, Depletion and Amortization (DD&A) of Oil and Gas Properties . We calculate depletion
+by using the capitalized costs in our full-cost pool plus future development and abandonment costs
+(combined, the depletable base) and our estimated net proved reserve quantities. Capitalized
+costs added to the full-cost pool and other costs added to the depletable base include the
+following:
+• 
+the cost of drilling and equipping productive wells, dry hole costs, acquisition costs
+of properties with proved reserves, delay rentals and other costs related to exploration
+and development of our oil and gas properties; 
+• 
+our payroll and general and administrative costs and costs related to fringe benefits
+paid to employees directly engaged in the acquisition, exploration and/or development of
+oil and gas properties as well as other directly identifiable general and administrative
+costs associated with such activities. Such capitalized costs do not include any costs
+related to our production of oil and gas or our general corporate overhead; 
+• 
+costs associated with properties that do not have proved reserves attributed to them are
+excluded from the full-cost pool. These unevaluated property costs are added to the
+full-cost pool at such time as wells are completed on the properties, the properties are
+sold or we determine these costs have been impaired. Our determination that a property has
+or has not been impaired (which is discussed below) requires that we make assumptions about
+future events; 
+• 
+our estimates of future costs to develop proved properties are added to the full-cost
+pool for purposes of the DD&A computation. We use assumptions based on the latest
+geologic, engineering, regulatory and cost data available to us to estimate these amounts.
+However, the estimates we make are subjective and may change over time. Our estimates of
+future development costs are periodically updated as additional information becomes
+available; and 
+• 
+prior to the adoption of SFAS 143, estimated costs to dismantle, abandon and restore a
+proved property were added to the full-cost pool for the purposes of DD&A. Subsequent to
+the adoption of SFAS 143, effective January 1, 2003, these costs are included in the
+full-cost pool. Such cost estimates are periodically updated as additional information
+becomes available. As discussed below specifically SFAS 143, beginning January 1, 2003, we
+changed the method for which we account for such costs. 
+Capitalized costs included in the full-cost pool are depleted and charged against earnings using
+the unit of production method. Under this method, we estimate our quantity of proved reserves at
+the beginning of each accounting period. For each barrel of oil equivalent produced during the
+period, we record a depletion charge equal to the amount included in the depletable base (net of
+accumulated depreciation, depletion and amortization) divided by our estimated net proved reserve
+quantities.
+Because we use estimates and assumptions to calculate proved reserves (as discussed below) and the
+amounts included in the full-cost pool, our depletion calculations will change if the estimates and
+assumptions are not realized. Such changes may be material.
+Ceiling Test . Under the full-cost accounting rules, capitalized costs included in the full-cost
+pool, net of accumulated depreciation, depletion and amortization (DD&A), cost of unevaluated
+properties and deferred income taxes, may not exceed the present value of our estimated future net
+cash flows from proved oil and gas reserves, discounted at 10%, plus the lower of cost or fair
+value of unproved properties included in the costs being amortized, net of related tax effects.
+These rules generally require that, in estimating future net cash flow, we assume that future oil
+and gas production will be sold at the unescalated market price for oil and gas received at the end
+of each fiscal quarter and that future costs to produce oil and gas will remain constant at the
+prices in effect at the end of the fiscal quarter. We are required to write-down and charge to
+29
+Table of Contents 
+earnings the amount, if any, by which these costs exceed the discounted future net cash flows,
+unless prices recover sufficiently before the date of our financial statements. Given the
+volatility of oil and gas prices, it is likely that our estimates of
+discounted future net cash flows from proved oil and gas reserves will change in the near term. If
+oil and gas prices decline significantly, even if only for a short period of time, it is possible
+that writedowns of oil and gas properties could occur in the future.
+Estimating Reserves and Present Values . The estimates of quantities of proved oil and gas reserves
+and the discounted present value of such reserves at the end of each quarter are based on numerous
+assumptions which are likely to change over time. These assumptions include:
+• 
+the prices at which we can sell our oil and gas production in the future. Oil and gas
+prices are volatile, but we are generally required to assume that they will not change from
+the prices in effect at the end of the quarter. In general, higher oil and gas prices will
+increase quantities of proved reserves and the present value of such reserves, while lower
+prices will decrease these amounts. Because our properties have relatively short
+productive lives, changes in prices will affect the present value more than quantities of
+oil and gas reserves; 
+• 
+the costs to develop and produce our reserves and the costs to dismantle our production
+facilities when reserves are depleted. These costs are likely to change over time, but we
+are required to assume that costs in effect at the end of the quarter will not change.
+Increases in costs will reduce oil and gas quantities and present values, while decreases
+in costs will increase such amounts. Because our properties have relatively short
+productive lives, changes in costs will affect the present value more than quantities of
+oil and gas reserves; and 
+• 
+the liability to pay royalties to the Mineral Management Service. See Note 7 of our
+Consolidated Financial Statements for a more detailed discussion of this potential
+liability. 
+In addition, the process of estimating proved oil and gas reserves requires that our independent
+and internal reserve engineers exercise judgment based on available geological, geophysical and
+technical information. We have described the risks associated with reserve estimation and the
+volatility of oil and gas prices, under “Risk Factors”.
+Unproved Properties . Costs associated with properties that do not have proved reserves, including
+capitalized interest, are excluded from the full-cost pool. These unproved properties are included
+in the line item “Unevaluated properties excluded from amortization.” Unproved property costs are
+transferred to the full-cost pool when wells are completed on the properties or the properties are
+sold. In addition, we are required to determine whether our unproved properties are impaired and,
+if so, add the costs of such properties to the full-cost pool. We determine whether an unproved
+property should be impaired by periodically reviewing our exploration program on a property by
+property basis. This determination may require the exercise of substantial judgment by our
+management.
+Asset Retirement Obligations. In June 2001, the FASB issued SFAS 143 effective for fiscal years
+beginning after June 15, 2002. SFAS 143 essentially requires entities to record the fair value of
+a liability for obligations associated with the retirement of tangible long-lived assets and the
+associated asset retirement costs. We adopted the statement on January 1, 2003 resulting in a
+cumulative effect of accounting change of $181,000, net of tax. See Note 8 to our Consolidated
+Financial Statements.
+Derivatives. We use derivative financial instruments for price protection purposes on a limited
+amount of our future production and do not use them for trading purposes. Such derivatives were
+accounted for in years prior to 2001 as hedges and have been recognized as an adjustment to oil and
+gas sales in the period in which they are related. We currently use the accounting treatment for
+derivatives specified under SFAS 133.
+30
+Table of Contents 
+See Note 6 to our Consolidated Financial Statements.
+Income Taxes. We follow the asset and liability method of accounting for deferred income taxes
+prescribed by Statement of Financial Accounting Standards No. 109 (“SFAS 109”) “Accounting for
+Income Taxes”. The statement provides for the recognition of a deferred tax asset for deductible
+temporary timing differences, capital and operating loss carryforwards, statutory depletion
+carryforward and tax credit carryforwards, net of a “valuation allowance”. The valuation allowance
+is provided for that portion of the asset, for which it is deemed more likely than not, that it
+will not be realized.
+SFAS 109 provides for the weighing of positive and negative evidence in determining whether it is
+more likely than not that a deferred tax asset is recoverable. We incurred losses in 2002 and 2003
+and had losses on an aggregate basis for the three-year period ended December 31, 2003. Because of
+these cumulative losses we established a full valuation allowance of $11.5 million as of December
+31, 2003.
+As a result of production from our first two deepwater projects starting in November 2003, as well
+as refinancing our highest cost debt in 2004, we achieved profitable operations and had income on
+an aggregate basis for the three-year period ended December 31, 2004. As a result, we reversed the
+valuation allowance in 2004 which had a balance of $7.0 million as of December 31, 2004. See Note
+3 to the Consolidated Financial Statements for further disclosure.
+Liquidity and Capital Resources 
+Historically, our primary sources of capital have been cash flows from operations, borrowings from
+financial institutions and the sale of debt and equity securities. Net cash and cash equivalents
+decreased during 2005 to $2.6 million, down $0.7 million. Cash provided from operating activities
+during 2005 totaled $74 million, up 4% from $71 million in 2004. Dividends paid on preferred stock
+in 2005 were $318,000.
+On June 15, 2004, we closed on a three-year senior secured credit facility underwritten by Union
+Bank of California, N.A. The credit facility includes a borrowing base, determined by the lender,
+of $70 million, which may be adjusted semi-annually and could increase to a maximum of $175
+million. As of December 31, 2005 there were no borrowings outstanding under the facility and we
+had an aggregate of $7.5 million in outstanding letters of credit issued under the credit facility.
+These letters of credit secure obligations under the outstanding hedging contracts described in
+Note 6 to the Consolidated Financial Statements. The outstanding letters of credit reduce the
+amount available for borrowings under the credit facility. As a result, $62.5 million was
+available for future borrowings under the credit facility as of December 31, 2005.
+In December 2003 and March 2004, we closed on our 9.75% senior notes due 2010 in the aggregate
+principal amount of $200 million. The net proceeds from these notes and the public offering of
+3,450,000 shares of common stock in the second quarter of 2004 were used to restructure our debt
+that was maturing in 2004 and 2005. See Note 5 to the Consolidated Financial Statements for a more
+detailed discussion of our debt restructure.
+The indenture governing our 9.75% senior notes due 2010 and our senior secured credit facility
+contain various covenants including restrictions on additional indebtedness and payment of cash
+dividends. In addition, our senior secured credit facility contains covenants for maintenance of
+certain financial ratios. We were in compliance with these covenants at December 31, 2005.
+31
+Table of Contents 
+Our oil and gas reserves as reported by Huddleston & Co., Inc. were 189 Bcfe of natural gas
+equivalents on December 31, 2005. Our cash flow from operations during 2005 was generated by the
+production of 18.8 Bcfe after incurring significant downtime at our major producing properties due
+to tropical storms
+and hurricanes during the last half of the year. Production of our reserves during 2006, without
+weather-related downtime, is projected to be higher than 2005 due to eight new discoveries
+scheduled to commence initial production during 2006 which will offset traditional declines from
+our current producing properties.
+Our planned capital expenditures for 2006 total $125 million. The current portion of our asset
+retirement obligation in the amount of $21.7 million and capitalized interest and general and
+administrative expenses are included in the $125 million. Capital expenditure plans for 2006
+include:
+• 
+the completion and development of pre-2006 shelf discoveries; 
+• 
+the discretionary drilling of approximately 18 shelf and onshore exploratory wells; 
+• 
+drilling of three deepwater prospects; 
+• 
+lease and seismic acquisition; and 
+• 
+capitalized interest and overhead. 
+We believe that our operating cash flow and our credit facility will be adequate to meet our
+capital, debt repayment, and operating requirements for 2006. We fund our day-to-day operating
+expenses and capital expenditures from operating cash flows, supplemented as needed by borrowings
+under our credit facility. In addition, we have sold debt and equity in both public and private
+offerings in the past, and we expect that these sources of capital will continue to be available to
+us in the future. Because of the liquidity and capital resources alternatives available to us,
+including internally generated cash flows, our management believes that our short-term and
+long-term liquidity is adequate to fund operations, including our capital spending program,
+repayment of maturing debt and any amounts that may ultimately be paid in connection with
+contingencies.
+Our cash flow, both in the short and long-term, is impacted by highly volatile oil and natural gas
+prices, production levels, industry trends impacting operating expenses and our ability to continue
+to acquire or find reserves at competitive prices. Cash flow forecasts for internal use by
+management are revised monthly in response to changing market conditions and production
+projections. We routinely adjust capital expenditure budgets within the planned total amount in
+response to the adjusted cash flow forecasts and market trends in drilling and acquisitions costs.
+32
+Table of Contents 
+The following table describes our outstanding contractual obligations (in thousands) as of December
+31, 2005:
+Payments due by Period 
+More 
+Contractual 
+Less Than 
+One-Three 
+Three-Five 
+Than-Five 
+Obligations 
+Total 
+One Year 
+Years 
+Years 
+Years 
+Senior Secured Credit Facility 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+9.75% Senior Notes 
+200,000 
+— 
+— 
+200,000 
+— 
+Capital lease (future minimum payments) 
+1,710 
+439 
+577 
+449 
+245 
+Throughput Commitments: 
+Medusa Spar LLC 
+12,684 
+3,836 
+5,532 
+3,316 
+— 
+Medusa Oil Pipeline 
+606 
+206 
+186 
+113 
+101 
+$ 
+215,000 
+$ 
+4,481 
+$ 
+6,295 
+$ 
+203,878 
+$ 
+346 
+Off-Balance Sheet Arrangements 
+In December 2003, we announced the formation of a limited liability company, Medusa Spar LLC, which
+now owns a 75% undivided ownership interest in the deepwater spar production facilities on our
+Medusa Field in the Gulf of Mexico. We contributed a 15% undivided ownership interest in the
+production facility to Medusa Spar LLC in return for approximately $25 million in cash and a 10%
+ownership interest in the LLC. The LLC will earn a tariff based upon production volume throughput
+from the Medusa area. We are obligated to process our share of production from the Medusa Field and
+any future discoveries in the area through the spar production facilities. This arrangement allows
+us to defer the cost of the spar production facility over the life of the Medusa Field. Our cash
+proceeds were used to reduce the balance outstanding under our senior secured credit facility. The
+LLC used the cash proceeds from $83.7 million of non-recourse financing and a cash contribution by
+one of the LLC owners to acquire its 75% interest in the spar. On December 31, 2005, $47.0 million
+of the financing was outstanding. The balance of Medusa Spar LLC is owned by Oceaneering
+International, Inc. and Murphy. We are accounting for our 10% ownership interest in the LLC under
+the equity method.
+2005 Hurricane Activity 
+During 2005, we encountered numerous tropical storms and hurricanes which caused all of our fields
+located in the Gulf of Mexico area to be shut-in at various times during the year. Hurricanes
+Katrina and Rita, being the most devastating of these tropical weather systems, caused substantial
+downtime in the third and fourth quarter of 2005 which was primarily due to damage incurred to oil
+and gas transmission lines and production facilities owned by third parties.
+Our major fields, Medusa, Habanero and Mobile Bay Blocks 863, 864, 907, 953 and 955, incurred
+damage; but the fields were repaired and brought back online in the fourth quarter of 2005. Our
+properties are insured and we expect to get reimbursed for most of our costs incurred for damage
+repairs, less our $250,000 deductible per occurrence. We estimated that our cost to repair the
+hurricane damages will be approximately $4.0 million. As of December 31, 2005, we had expensed
+$1.2 million for damages related to tropical storms and hurricanes for deductibles and the costs of
+repairs not covered by our property insurance carrier.
+33
+Table of Contents 
+The tropical storms and hurricanes during 2005 had a significant impact on our cash flows from
+properties. Scheduled below are our major properties which incurred lost production days:
+Field 
+Production Days Lost 
+Medusa 
+102 
+Habanero 
+85 
+Mobile Block 864 Unit 
+48 
+Mobile 953 
+48 
+Mobile 955 
+136 
+High Island 119 
+102 
+These properties account for 86% of our production for 2005. In addition, initial production from
+our recent discoveries at North Padre Island Block 913 and East Cameron Block 90 were delayed due
+to equipment availability problems. See “Significant Properties” for more detail by property.
+We are in the process of negotiating our insurance renewal for the year ended March 31, 2007. We
+expect our insurance premiums to increase but can not estimate the amount at this time.
+34
+Table of Contents 
+Results of Operations 
+The following table sets forth certain operating information with respect to our oil and gas
+operations for each of the three years in the period ended December 31, 2005.
+December 31, 
+2005 
+2004 
+2003 
+Production: 
+Oil (MBbls) 
+1,837 
+1,736 
+268 
+Gas (MMcf) 
+7,768 
+11,387 
+12,315 
+Total production (MMcfe) 
+18,787 
+21,801 
+13,923 
+Average daily production (MMcfe) 
+51.5 
+59.6 
+38.1 
+Average sales price: 
+Oil (per Bbl) (a) 
+$ 
+41.61 
+$ 
+28.71 
+$ 
+28.72 
+Gas (per Mcf) 
+$ 
+8.35 
+$ 
+6.15 
+$ 
+5.36 
+Total (per Mcfe) 
+$ 
+7.52 
+$ 
+5.50 
+$ 
+5.29 
+Oil and Gas revenues (in thousands): 
+Oil revenue 
+$ 
+76,425 
+$ 
+49,826 
+$ 
+7,696 
+Gas revenue 
+64,865 
+69,976 
+66,001 
+Total 
+$ 
+141,290 
+$ 
+119,802 
+$ 
+73,697 
+Oil and gas production costs (in thousands): 
+Lease operating expenses 
+$ 
+24,377 
+$ 
+22,308 
+$ 
+11,301 
+Additional per Mcfe data: 
+Sales price 
+$ 
+7.52 
+$ 
+5.50 
+$ 
+5.29 
+Lease operating expenses 
+1.30 
+1.02 
+.81 
+Operating margin 
+$ 
+6.22 
+$ 
+4.48 
+$ 
+4.48 
+Depletion 
+$ 
+2.39 
+$ 
+2.18 
+$ 
+2.03 
+Accretion 
+$ 
+.19 
+$ 
+.16 
+$ 
+.21 
+General and administrative (net of management fees) 
+$ 
+.43 
+$ 
+.40 
+$ 
+.34 
+(a) Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil: 
+Average NYMEX oil price 
+$ 
+56.57 
+$ 
+41.38 
+$ 
+31.08 
+Basis differential and quality adjustments 
+(8.45 
+) 
+(4.60 
+) 
+(1.94 
+) 
+Transportation 
+(1.26 
+) 
+(1.27 
+) 
+(0.42 
+) 
+Hedging 
+(5.25 
+) 
+(6.80 
+) 
+— 
+Average realized oil price 
+$ 
+41.61 
+$ 
+28.71 
+$ 
+28.72 
+35
+Table of Contents 
+Comparison of Results of Operations for the Years Ended December 31, 2005 and 2004 
+Oil and Gas Revenues 
+Total oil and gas revenues increased 18% from $119.8 million in 2004 to $141.3 million in 2005
+primarily due to pricing. Total production for 2005 decreased by 14% versus 2004 as a result of
+downtime associated with the tropical storm and hurricane activity in 2005.
+Gas production during 2005 totaled 7.8 Bcf and generated $64.9 million in revenues compared to 11.4
+Bcf and $70.0 million in revenues during the same period in 2004. Average gas prices realized for
+2005 were $8.35 per Mcf compared to $6.15 per Mcf during the same period last year. The decrease
+in production was primarily due to significant downtime related to tropical storm and hurricane
+activity and the normal and expected decline in production from our Mobile area fields and older
+properties. See our discussion of “Significant Properties” for a more detailed discussion by
+property of this downtime.
+Oil production during 2005 totaled 1,837,000 barrels and generated $76.4 million in revenues
+compared to 1,736,000 barrels and $49.8 million in revenues for the same period in 2004. Average
+oil prices realized in 2005 were $41.61 per barrel compared to $28.71 per barrel in 2004. Oil
+production increased during 2005 despite significant downtime resulting from tropical storms and
+hurricanes. The increase was primarily attributable to our deepwater property Medusa which began
+production in 2003 from a single well with five others being brought online during 2004 and all six
+producing during 2005. In addition, our North Medusa discovery was completed and initial
+production commenced through the field facilities in April 2005. See our discussion of
+“Significant Properties” for more detail regarding production and downtime.
+Lease Operating Expenses 
+Lease operating expenses for 2005 increased by 9% to $24.4 million compared to $22.3 million for
+the same period in 2004. The increase was primarily due to lease operating expenses related to our
+deepwater discovery, Medusa, which had higher throughput charges as a result of higher production
+rates and the addition of our High Island Block 119 field, which began producing late in the third
+quarter of 2004.
+In addition, lease operating expenses for 2005 included the costs of repairs to our properties for
+damages caused by tropical storms and hurricanes in the net amount of $1.2 million. This amount
+covers the deductibles and an estimate of repairs not expected to be reimbursed by our property
+insurance carrier.
+Depreciation, Depletion and Amortization 
+Depreciation, depletion and amortization for 2005 and 2004 were $44.9 million and $47.5 million,
+respectively. The 5% decrease was primarily due to lower production volumes for 2005 compared to
+2004. The decrease was partially offset by a higher average depletion rate.
+Accretion Expense 
+Accretion expense for 2005 and 2004 of $3.5 million and $3.4 million, respectively, represents
+accretion for our asset retirement obligations. The increase was due to the addition of plugging
+and abandonment obligations. See Note 8 to the Consolidated Financial Statements.
+36
+Table of Contents 
+General and Administrative 
+General and administrative expenses for 2005, net of amounts capitalized, were $8.1 million
+compared to $8.8 million incurred in 2004. There was a charge in general and administrative
+expenses of $2.6 million in the first
+quarter of 2004 for the early retirement of two executive officers of the Company. The decrease
+was partially offset by reduced capitalized overhead for 2005 and a non-cash charge during the
+second quarter of 2005 for the accelerated vesting of performance shares in the amount of $930,000
+for an executive officer and two directors of the Company, two of whom are deceased.
+Interest Expense 
+Interest expense decreased by 17% in 2005 to $16.7 million compared to $20.1 million in 2004. This
+decrease is primarily attributable to an equity offering completed in the second quarter of 2004 in
+which a portion of the proceeds were used to redeem $33 million of 11% Senior Subordinated Notes .
+Loss on Early Extinguishment of Debt 
+A loss of $3.0 million was incurred in 2004 for the write-off of deferred financing costs,
+pre-payment premiums and bond discounts associated with the early extinguishment of debt.
+Income Taxes 
+For 2005, we had an income tax expense of $13.2 million compared to an income tax benefit of $6.7
+million in 2004. The income tax benefit for 2004 resulted primarily from the reversal of the
+valuation allowance established in 2003 against our deferred tax asset. As a result of production
+from the Company’s first two deepwater projects starting in November 2003, as well as refinancing
+its highest cost debt in 2004, the Company achieved profitable operations and has income on an
+aggregate basis for the three-year period ended December 31, 2004 and the Company reversed the
+valuation allowance. See Note 3 to our Consolidated Financial Statements for a more detailed
+discussion.
+37
+Table of Contents 
+Comparison of Results of Operations for the Years Ended December 31, 2004 and 2003 
+Oil and Gas Revenues 
+Total production for 2004 increased by 57% versus 2003 and total oil and gas revenues increased 63%
+from $73.7 million in 2003 to $119.8 million in 2004. Increased production was primarily due to our
+deepwater discoveries, Medusa and Habanero, which began producing late in the fourth quarter of
+2003.
+Gas production during 2004 totaled 11.4 Bcf and generated $70.0 million in revenues compared to
+12.3 Bcf and $66.0 million in revenues during the same period in 2003. Average gas prices realized
+for 2004 were $6.15 per Mcf compared to $5.36 per Mcf during the same period the previous year.
+The decrease in production was primarily due to downtime for Hurricane Ivan and the normal and
+expected decline in production from our Mobile area fields and older properties. These factors
+were partially offset by production from Medusa and Habanero.
+Oil production during 2004 totaled 1,736,000 barrels and generated $49.8 million in revenues
+compared to 268,000 barrels and $7.7 million in revenues for the same period in 2003. Average oil
+prices realized in 2004 were $28.71 per barrel compared to $28.72 per barrel in 2003. The increase
+in production was due to the initial production from our deepwater discoveries, Medusa and
+Habanero. The production increase was offset slightly by downtime for Hurricane Ivan and normal
+and expected declines in production from older properties.
+Lease Operating Expenses 
+Lease operating expenses for 2004 increased by 97% to $22.3 million compared to $11.3 million for
+the same period in 2003. The increase was primarily due to lease operating expenses related to our
+deepwater discoveries, Medusa and Habanero.
+Depreciation, Depletion and Amortization 
+Depreciation, depletion and amortization for 2004 and 2003 were $47.5 million and $28.3 million,
+respectively. The 68% increase was primarily due to higher production volumes for 2004 compared to
+2003.
+Accretion Expense 
+Accretion expense for 2004 and 2003 of $3.4 million and $2.9 million, respectively, represents
+accretion for our asset retirement obligations. The increase was due to the addition of plugging
+and abandonment obligations. See Note 8 to the Consolidated Financial Statements.
+General and Administrative 
+General and administrative expenses for 2004, net of amounts capitalized, were $8.8 million
+compared to $4.7 million incurred in 2003. There was a charge in general and administrative
+expenses of $2.6 million in the first quarter of 2004 for the early retirement of two executive
+officers of the Company. Also reduced capitalized overhead, higher directors’ fees, and increased
+independent and internal audit costs resulting from the implementation of The Sarbanes-Oxley Act,
+Section 404 contributed to the increase in general and administrative expenses.
+38
+Table of Contents 
+Interest Expense 
+Interest expense decreased by 34% in 2004 to $20.1 million compared to $30.6 million in 2003. This
+is a result of lower debt levels and lower interest rates due to the restructuring of debt in
+December 2003 and during the six-month period ended June 30, 2004 in additional to an equity
+offering completed in the
+second quarter of 2004. In addition, amortization of deferred financing costs and bond discounts
+decreased due to the write-off of unamortized deferred financing costs and bond discounts
+associated with the early extinguishment of debt.
+Loss on Early Extinguishment of Debt 
+A loss of $3.0 million and $5.6 million was incurred in 2004 and 2003, respectively. Both were
+incurred for the write-off of deferred financing costs, pre-payment premiums and bond discounts
+associated with the early extinguishment of debt.
+Income Taxes 
+The income tax benefit of $6.7 million in 2004 resulted primarily from the reversal of the
+valuation allowance established in 2003 against our deferred tax asset. As a result of production
+from the Company’s first two deepwater projects starting in November 2003, as well as refinancing
+its highest cost debt in 2004, the Company achieved profitable operations and has income on an
+aggregate basis for the three-year period ended December 31, 2004 and the Company reversed the
+valuation allowance. See Note 3 to our Consolidated Financial Statements for a more detailed
+discussion.
+39
+Table of Contents 
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS 
+The Company’s revenues are derived from the sale of its crude oil and natural gas production.
+Recently the prices for oil and gas have increased; however, they remain extremely volatile and
+sometimes experience large fluctuations as a result of relatively small changes in supplies,
+weather conditions,
+economic conditions and government actions. The Company enters into short-term derivative
+financial instruments to hedge oil and gas price risks for the production volumes to which the
+hedge relates. The derivatives reduce the Company’s exposure on the hedged volumes to decreases in
+commodity prices and limit the benefit the Company might otherwise have received from any increases
+in commodity prices on the hedged volumes.
+The Company also enters into price “collars” to reduce the risk of changes in oil and gas prices.
+Under these arrangements, no payments are due by either party so long as the market price is above
+the floor price set in the collar and below the ceiling. If the price falls below the floor, the
+counter-party to the collar pays the difference to the Company and if the price is above the
+ceiling, the counter-party receives the difference from the Company. Another type of hedging
+contract Callon has entered into is a put contract. Under a put, if the price falls below the set
+floor price, the counter-party to the contract pays the difference to the Company. The Company
+enters into these various agreements to reduce the effects of volatile oil and gas prices and does
+not enter into hedge transactions for speculative purposes. See Note 6 to the Consolidated
+Financial Statements for a description of the Company’s hedged position at December 31, 2005.
+There have been no significant changes in market risks faced by the Company since the end of 2005.
+Based on projected annual sales volumes for 2006 (excluding forecast production increases over
+2005), a 10% decline in the prices Callon receives for its crude oil and natural gas production
+would have an approximate $18 million impact on our revenues.
+40
+Table of Contents 
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+Page 
+Report of Independent Registered Public Accounting Firm 
+42 
+Consolidated Balance Sheets as of December 31, 2005
+and 2004 
+43 
+Consolidated Statements of Operations for Each of the Three Years
+in the Period Ended December 31, 2005 
+44 
+Consolidated Statements of Stockholders’ Equity
+for Each of the Three Years in the Period Ended December 31, 2005 
+45 
+Consolidated Statements of Cash Flows for Each of the Three Years
+in the Period Ended December 31, 2005 
+46 
+Notes to Consolidated Financial Statements 
+47 
+41
+Table of Contents 
+Report of Independent Registered Public Accounting Firm
+The Stockholders and Board of Directors 
+Callon Petroleum Company
+We have audited the accompanying consolidated balance sheets of Callon Petroleum Company as of
+December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’
+equity and cash flows for each of the three years in the period ended December 31, 2005. These
+financial statements are the responsibility of the Company’s management. Our responsibility is to
+express an opinion on these financial statements based on our audits.
+We conducted our audits in accordance with the standards of the Public Company Accounting
+Oversight Board (United States). Those standards require that we plan and perform the audit to
+obtain reasonable assurance about whether the financial statements are free of material
+misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
+disclosures in the financial statements. An audit also includes assessing the accounting
+principles used and significant estimates made by management, as well as evaluating the overall
+financial statement presentation. We believe that our audits provide a reasonable basis for our
+opinion.
+In our opinion, the financial statements referred to above present fairly, in all material
+respects, the consolidated financial position of Callon Petroleum Company as of December 31, 2005
+and 2004, and the results of its operations and its cash flows for each of the three years in the
+period ended December 31, 2005, in conformity with U.S.
+generally accepted accounting principles.
+As discussed in Note 1 to the financial statements, effective January 1, 2003, the Company
+adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement
+Obligations”.
+We also have audited, in accordance with the standards of the Public Company Accounting
+Oversight Board (United States), the effectiveness of Callon Petroleum Company’s internal control
+over financial reporting as of December 31, 2005, based on criteria established in Internal
+Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
+Commission and our report dated March 9, 2006, expressed an unqualified opinion thereon.
+/s/Ernst & Young LLP
+New Orleans, Louisiana 
+March 9, 2006
+42
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED BALANCE SHEETS 
+(In thousands, except share data) 
+December 31, 
+2005 
+2004 
+ASSETS 
+Current assets: 
+Cash and cash equivalents 
+$ 
+2,565 
+$ 
+3,266 
+Accounts receivable 
+33,195 
+14,928 
+Deferred tax asset-current 
+26,770 
+5,676 
+Restricted investments-current 
+4,110 
+2,055 
+Fair market value of derivatives 
+889 
+1,570 
+Other current assets 
+1,998 
+581 
+Total current assets 
+69,527 
+28,076 
+Oil and gas properties, full-cost accounting method: 
+Evaluated properties 
+937,698 
+862,101 
+Less accumulated depreciation, depletion and amortization 
+(539,399 
+) 
+(494,453 
+) 
+398,299 
+367,648 
+Unevaluated properties excluded from amortization 
+49,065 
+39,042 
+Total oil and gas properties 
+447,364 
+406,690 
+Other property and equipment, net 
+1,605 
+1,541 
+Deferred tax asset 
+— 
+2,986 
+Long-term gas balancing receivable 
+403 
+725 
+Restricted investments 
+1,858 
+5,687 
+Investment in Medusa Spar LLC 
+11,389 
+9,787 
+Other assets, net 
+1,630 
+2,031 
+Total assets 
+$ 
+533,776 
+$ 
+457,523 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued liabilities 
+$ 
+39,323 
+$ 
+15,728 
+Fair market value of derivatives 
+1,247 
+2,993 
+Undistributed oil and gas revenues 
+721 
+1,162 
+Accrued net profits interest payable 
+— 
+1,927 
+Suspended Medusa oil royalties 
+— 
+5,430 
+Asset retirement obligations-current 
+21,660 
+13,300 
+Current maturities of long-term debt 
+263 
+576 
+Total current liabilities 
+63,214 
+41,116 
+Long-term debt 
+188,813 
+192,351 
+Asset retirement obligations 
+16,613 
+24,982 
+Deferred tax liability 
+31,633 
+— 
+Accrued liabilities to be refinanced 
+5,000 
+— 
+Other long-term liabilities 
+455 
+762 
+Total liabilities 
+305,728 
+259,211 
+Stockholders’ equity: 
+Preferred Stock, $.01 par value; 2,500,000 shares authorized;
+-0- and 596,671 shares of Convertible Exchangeable Preferred
+Stock, Series A issued and outstanding at December 31,
+2005 and 2004, respectively 
+— 
+6 
+Common Stock, $.01 par value; 30,000,000 shares
+authorized; 19,357,138 shares and 17,616,596 shares issued
+and
+outstanding at December 31, 2005 and 2004, respectively 
+194 
+176 
+Unearned compensation-restricted stock 
+(3,334 
+) 
+(5,352 
+) 
+Capital in excess of par value 
+220,360 
+220,664 
+Other comprehensive loss 
+(331 
+) 
+(1,883 
+) 
+Retained earnings (deficit) 
+11,159 
+(15,299 
+) 
+Total stockholders’ equity 
+228,048 
+198,312 
+Total liabilities and stockholders’ equity 
+$ 
+533,776 
+$ 
+457,523 
+The accompanying notes are an integral part of these financial statements.
+43
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Statements of Operations 
+For the Years Ended December 31, 2005, 2004 and 2003 
+(In thousands, except per share amounts) 
+2005 
+2004 
+2003 
+Operating revenues: 
+Oil and gas sales 
+$ 
+141,290 
+$ 
+119,802 
+$ 
+73,697 
+Operating expenses: 
+Lease operating expenses 
+24,377 
+22,308 
+11,301 
+Depreciation, depletion and amortization 
+44,946 
+47,453 
+28,253 
+General and administrative 
+8,085 
+8,758 
+4,713 
+Accretion expense 
+3,549 
+3,400 
+2,884 
+Derivative expense 
+6,028 
+1,371 
+535 
+Total operating expenses 
+86,985 
+83,290 
+47,686 
+Income from operations 
+54,305 
+36,512 
+26,011 
+Other (income) expenses: 
+Interest expense 
+16,660 
+20,137 
+30,614 
+Other (income) 
+(998 
+) 
+(357 
+) 
+(444 
+) 
+Loss on early extinguishment of debt 
+— 
+3,004 
+5,573 
+Total other (income) expenses 
+15,662 
+22,784 
+35,743 
+Income (loss) before income taxes 
+38,643 
+13,728 
+(9,732 
+) 
+Income tax expense (benefit) 
+13,209 
+(6,697 
+) 
+8,432 
+Income (loss) before Medusa Spar LLC and cumulative
+effect of change in accounting principle 
+25,434 
+20,425 
+(18,164 
+) 
+Income (loss) on Medusa Spar LLC, net of tax 
+1,342 
+1,076 
+(8 
+) 
+Income (loss) before cumulative effect of change in
+accounting principle 
+26,776 
+21,501 
+(18,172 
+) 
+Cumulative effect of change in accounting principle, net of tax 
+— 
+— 
+181 
+Net income (loss) 
+26,776 
+21,501 
+(17,991 
+) 
+Preferred stock dividends 
+318 
+1,272 
+1,277 
+Net income (loss) available to common shares 
+$ 
+26,458 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+Net income (loss) per common share: 
+Basic 
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+1.43 
+$ 
+1.28 
+$ 
+(1.42 
+) 
+Cumulative effect of change in accounting principle, net of
+tax 
+— 
+— 
+0.01 
+Net income (loss) available to common share 
+$ 
+1.43 
+$ 
+1.28 
+$ 
+(1.41 
+) 
+Diluted 
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+1.28 
+$ 
+1.22 
+$ 
+(1.42 
+) 
+Cumulative effect of change in accounting principle, net of
+tax 
+— 
+— 
+0.01 
+Net income (loss) available to common share 
+$ 
+1.28 
+$ 
+1.22 
+$ 
+(1.41 
+) 
+Shares used
+in computing net income (loss) per share amounts: 
+Basic 
+18,453 
+15,796 
+13,662 
+Diluted 
+20,883 
+17,678 
+13,662 
+The accompanying notes are an integral part of these financial statements.
+44
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY 
+(In thousands) 
+Unearned 
+Accumulated 
+Total 
+Restricted 
+Capital in 
+Other 
+Retained 
+Stock- 
+Preferred 
+Common 
+Stock 
+Excess of 
+Comprehensive 
+Earnings 
+holders’ 
+Stock 
+Stock 
+Compensation 
+Par Value 
+Income (Loss) 
+(Deficit) 
+Equity 
+Balances, December 31, 2002 
+$ 
+6 
+$ 
+139 
+$ 
+(826 
+) 
+$ 
+158,370 
+$ 
+(469 
+) 
+$ 
+(16,260 
+) 
+$ 
+140,960 
+Comprehensive income (loss): 
+Net loss 
+— 
+— 
+— 
+— 
+— 
+(17,991 
+) 
+Other comprehensive income 
+— 
+— 
+— 
+— 
+449 
+— 
+Total comprehensive loss 
+(17,542 
+) 
+Preferred stock dividends 
+— 
+— 
+— 
+— 
+— 
+(1,277 
+) 
+(1,277 
+) 
+Shares issued pursuant to employee
+benefit and option plan 
+— 
+1 
+— 
+427 
+— 
+— 
+428 
+Employee stock purchase plan 
+— 
+— 
+— 
+127 
+— 
+— 
+127 
+Restricted stock 
+— 
+(1 
+) 
+454 
+(516 
+) 
+— 
+— 
+(63 
+) 
+Warrants 
+— 
+— 
+— 
+10,628 
+— 
+— 
+10,628 
+Balances, December 31, 2003 
+6 
+139 
+(372 
+) 
+169,036 
+(20 
+) 
+(35,528 
+) 
+133,261 
+Comprehensive income (loss): 
+Net income 
+— 
+— 
+— 
+— 
+— 
+21,501 
+Other comprehensive (loss) 
+— 
+— 
+— 
+— 
+(1,863 
+) 
+— 
+Total comprehensive income 
+19,638 
+Preferred stock dividend 
+— 
+— 
+— 
+— 
+— 
+(1,272 
+) 
+(1,272 
+) 
+Sale of common stock 
+— 
+35 
+— 
+44,012 
+— 
+— 
+44,047 
+Shares issued pursuant to employee
+benefit and option plan 
+— 
+1 
+— 
+720 
+— 
+— 
+721 
+Employee stock purchase plan 
+— 
+1 
+— 
+208 
+— 
+— 
+209 
+Tax benefits related to stock
+compensation plans 
+— 
+— 
+— 
+1,214 
+— 
+— 
+1,214 
+Restricted stock 
+— 
+— 
+(4,980 
+) 
+5,474 
+— 
+— 
+494 
+Balances, December 31, 2004 
+6 
+176 
+(5,352 
+) 
+220,664 
+(1,883 
+) 
+(15,299 
+) 
+198,312 
+Comprehensive income (loss): 
+Net income 
+— 
+— 
+— 
+— 
+— 
+26,776 
+Other comprehensive income 
+— 
+— 
+— 
+— 
+1,552 
+— 
+Total comprehensive income 
+28,328 
+Preferred stock dividend 
+— 
+— 
+— 
+— 
+— 
+(318 
+) 
+(318 
+) 
+Conversion of preferred shares
+to common stock 
+(6 
+) 
+13 
+— 
+(643 
+) 
+— 
+— 
+(636 
+) 
+Shares issued pursuant to employee
+benefit and option plan 
+— 
+1 
+— 
+(325 
+) 
+— 
+— 
+(324 
+) 
+Employee stock purchase plan 
+— 
+— 
+— 
+(33 
+) 
+— 
+— 
+(33 
+) 
+Tax benefits related to stock
+compensation plans 
+— 
+— 
+— 
+1,029 
+— 
+— 
+1,029 
+Restricted stock 
+— 
+2 
+2,018 
+(330 
+) 
+— 
+— 
+1,690 
+Warrants 
+— 
+2 
+— 
+(2 
+) 
+— 
+— 
+— 
+Balances, December 31, 2005 
+$ 
+— 
+$ 
+194 
+$ 
+(3,334 
+) 
+$ 
+220,360 
+$ 
+(331 
+) 
+$ 
+11,159 
+$ 
+228,048 
+The accompanying notes are an integral part of these financial statements.
+45
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+For the Years Ended December 31, 2005, 2004 and 2003 
+(In thousands) 
+2005 
+2004 
+2003 
+Cash flows from operating activities: 
+Net income (loss) 
+$ 
+26,776 
+$ 
+21,501 
+$ 
+(17,991 
+) 
+Adjustments to reconcile net income (loss) to
+cash provided by operating activities: 
+Depreciation, depletion and amortization 
+45,657 
+48,164 
+29,264 
+Accretion expense 
+3,549 
+3,400 
+2,884 
+Amortization of deferred financing costs 
+2,062 
+1,929 
+6,568 
+Non-cash loss on extinguishment of debt 
+— 
+2,910 
+4,423 
+Income from investment in Medusa Spar, LLC 
+(1,342 
+) 
+(1,076 
+) 
+— 
+Cumulative effect of change in accounting principle 
+— 
+— 
+(181 
+) 
+Non-cash derivative expense 
+1,635 
+(135 
+) 
+487 
+Deferred income tax expense (benefit) 
+13,209 
+(6,697 
+) 
+8,432 
+Non-cash charge related to compensation plans 
+1,906 
+1,225 
+858 
+Changes in current assets and liabilities: 
+Accounts receivable, trade 
+(11,169 
+) 
+(4,495 
+) 
+(1,438 
+) 
+Other current assets 
+670 
+971 
+(2,667 
+) 
+Current liabilities 
+(8,666 
+) 
+2,903 
+5,185 
+Change in gas balancing receivable 
+322 
+376 
+(340 
+) 
+Change in gas balancing payable 
+(289 
+) 
+400 
+(491 
+) 
+Change in other long-term liabilities 
+(18 
+) 
+(20 
+) 
+(15 
+) 
+Change in other assets, net 
+(292 
+) 
+(448 
+) 
+(349 
+) 
+Cash provided by operating activities 
+74,010 
+70,908 
+34,629 
+Cash flows from investing activities: 
+Capital expenditures 
+(73,072 
+) 
+(64,649 
+) 
+(50,705 
+) 
+Distribution from Medusa Spar, LLC 
+463 
+339 
+24,908 
+Proceeds from sale of pipeline and other facilities 
+— 
+— 
+1,500 
+Proceeds from sale of mineral interests 
+— 
+— 
+982 
+Cash used by investing activities 
+(72,609 
+) 
+(64,310 
+) 
+(23,315 
+) 
+Cash flows from financing activities: 
+Change in accrued liabilities to be refinanced 
+5,000 
+— 
+(3,861 
+) 
+Increase in debt 
+7,000 
+90,000 
+198,000 
+Payments on debt 
+(12,000 
+) 
+(205,915 
+) 
+(133,000 
+) 
+Restricted cash 
+— 
+63,345 
+(63,345 
+) 
+Debt issuance cost 
+— 
+(984 
+) 
+(3,745 
+) 
+Issuance of common stock 
+2 
+44,047 
+— 
+Buyout of preferred stock 
+(637 
+) 
+— 
+— 
+Equity issued related to employee stock plans 
+(573 
+) 
+199 
+127 
+Capital leases 
+(576 
+) 
+(1,452 
+) 
+(1,320 
+) 
+Cash dividends on preferred stock 
+(318 
+) 
+(1,272 
+) 
+(1,277 
+) 
+Cash used by financing activities 
+(2,102 
+) 
+(12,032 
+) 
+(8,421 
+) 
+Net increase (decrease) in cash and cash equivalents 
+(701 
+) 
+(5,434 
+) 
+2,893 
+Cash and short-term investments: 
+Balance, beginning of period 
+3,266 
+8,700 
+5,807 
+Balance, end of period 
+$ 
+2,565 
+$ 
+3,266 
+$ 
+8,700 
+The accompanying notes are an integral part of these financial statements.
+46
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+1. ORGANIZATION 
+General 
+Callon Petroleum Company (“the Company” or “Callon”) was organized under the laws of the state of
+Delaware in March 1994 to serve as the surviving entity in the consolidation and combination of
+several related entities (referred to herein collectively as the “Constituent Entities”). The
+combination of the businesses and properties of the Constituent Entities with the Company was
+completed on September 16, 1994 (“Consolidation”).
+As a result of the Consolidation, all of the businesses and properties of the Constituent Entities
+are owned (directly or indirectly) by the Company. Certain registration rights were granted to the
+stockholders of certain of the Constituent Entities. See Note 7.
+The Company and its predecessors have been engaged in the acquisition, development and exploration
+of crude oil and natural gas since 1950. The Company’s properties are geographically concentrated
+in Louisiana, Alabama and offshore Gulf of Mexico.
+2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 
+Principles of Consolidation and Reporting 
+The Consolidated Financial Statements include the accounts of the Company, and its subsidiary,
+Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries, namely Callon Offshore
+Production, Inc. and Mississippi Marketing, Inc. All intercompany accounts and transactions have
+been eliminated. Certain prior year amounts have been reclassified to conform to presentation in
+the current year.
+Use of Estimates 
+The preparation of financial statements in conformity with generally accepted accounting principles
+requires management to make estimates and assumptions that affect the reported amounts of assets
+and liabilities and disclosure of contingent assets and liabilities at the date of the financial
+statements and the reported amounts of revenues and expenses during the reporting period. Actual
+results could differ from those estimates.
+Asset Retirement Obligations 
+In June 2001, the FASB issued Statement of Financial Accounting Standards No. 143, “Accounting for
+Asset Retirement Obligations” (“SFAS 143”), effective for fiscal years beginning after June 15,
+2002. SFAS 143 essentially requires entities to record the fair value of a liability for
+obligations associated with the retirement of tangible long-lived assets and the associated asset
+retirement costs. Callon adopted SFAS 143 on January 1, 2003 resulting in a cumulative effect of
+accounting change of $181,000, net of tax. See Note 8.
+47
+Table of Contents 
+Oil and Gas Properties 
+The Company follows the full-cost method of accounting for oil and gas properties whereby all costs
+incurred in connection with the acquisition, exploration and development of oil and gas reserves,
+including certain overhead costs, are capitalized. Such amounts include the cost of drilling and
+equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest
+capitalized on unevaluated leases and other costs related to exploration and development
+activities. General and administrative costs capitalized include salaries and related fringe
+benefits paid to employees directly engaged in the acquisition, exploration and/or development of
+oil and gas properties as well as other directly identifiable general and administrative costs
+associated with such activities. Such capitalized costs ($7.1 million in 2005, $7.2 million in 2004
+and $8.4 million in 2003) do not include any costs related to production or general corporate
+overhead. Costs associated with unevaluated properties, including capitalized interest on such
+costs, are excluded from amortization. Unevaluated property costs are transferred to evaluated
+property costs at such time as wells are completed on the properties, the properties are sold or
+management determines that these costs have been impaired.
+Costs of properties, including future development and future site restoration, dismantlement and
+abandonment costs, which have proved reserves and properties which have been determined to be
+worthless, are depleted using the unit-of-production method based on proved reserves. If the total
+capitalized costs of oil and gas properties, net of accumulated amortization and deferred taxes
+relating to oil and gas properties, exceed the sum of (1) the estimated future net revenues from
+proved reserves at current prices discounted at 10% and (2) the lower of cost or market of
+unevaluated properties (the full-cost ceiling amount), net of tax effects, then such excess is
+charged to expense during the period in which the excess occurs. See Note 9.
+Upon the acquisition or discovery of oil and gas properties, management estimates the future net
+costs to be incurred to dismantle, abandon and restore the property using available geological,
+engineering and regulatory data. Such cost estimates are periodically updated for changes in
+conditions and requirements. Such estimated amounts are considered as part of the full-cost pool
+subject to amortization upon acquisition or discovery. Until January 1, 2003, such costs were
+capitalized as oil and gas properties as the actual restoration, dismantlement and abandonment
+activities took place. As discussed above under “Asset Retirement Obligations,” beginning January
+1, 2003, the Company changed the method for which we account for such costs upon adoption of SFAS
+143 and these costs are now capitalized to the full cost pool when the related liabilities are
+incurred in accordance with the provisions of SFAS 143. In accordance with the SEC issued Staff
+Accounting Bulleting No. 106, assets recorded in connection with the recognition of an asset
+retirement obligation pursuant to SFAS 143 are included as part of the costs subject to the
+full-cost ceiling limitation. The future cash outflows associated with settling the recorded asset
+retirement obligations are excluded from the computation of the present value of estimated future
+net revenues used in applying the ceiling test.
+Property and Equipment 
+Depreciation of other property and equipment is provided using the straight-line method over
+estimated lives of three to 20 years. Depreciation of pipeline and other facilities is provided
+using the straight-line method over estimated lives of 15 to 27 years. Depreciation expense of
+$227,000, $346,000 and $578,000 relating to other property and equipment was included in general
+and administrative expenses in the Company’s statements of operations for the years ended December
+31, 2005, 2004 and 2003, respectively. The accumulated depreciation on other property and
+equipment was $10.6 million and $10.4 million as of December 31, 2005 and 2004, respectively.
+48
+Table of Contents 
+Investment in Medusa Spar LLC 
+In December 2003, the Company announced the formation of a limited liability company, Medusa Spar
+LLC, which now owns a 75% undivided ownership interest in the deepwater spar production facilities
+on Callon’s Medusa Field in the Gulf of Mexico. The Company contributed a 15% undivided ownership
+interest in the production facility to Medusa Spar LLC in return for approximately $25 million in
+cash and a 10% ownership interest in the LLC. The LLC will earn a tariff based upon production
+volume throughput from the Medusa area. Callon is obligated to process our share of production from
+the Medusa Field and any future discoveries in the area through the spar production facilities.
+This arrangement allows Callon to defer the cost of the spar production facility over the life of
+the Medusa Field. The Company’s cash proceeds were used to reduce the balance outstanding under
+its senior secured credit facility. The LLC used the cash proceeds from $83.7 million of
+non-recourse financing and a cash contribution by one of the LLC owners to acquire its 75% interest
+in the spar. On December 31, 2005, $47.0 million of the financing was outstanding. The balance of
+Medusa Spar LLC is owned by Oceaneering International, Inc. (NYSE:OII) and Murphy Oil Corporation
+(NYSE:MUR). The Company is accounting for our 10% ownership interest in the LLC under the equity
+method.
+Natural Gas Imbalances 
+The Company follows the entitlement method of accounting for its proportionate share of gas
+production on a well-by-well basis, recording a receivable to the extent that a well is in an
+“undertake” position and conversely recording a liability to the extent that a well is in an
+“overtake” position. Gas balancing receivables were $403,000 and $725,000 as of December 31, 2005
+and 2004, respectively. Gas balancing payables were $304,000 and $594,000 as of December 31, 2005
+and 2004, respectively.
+Derivatives 
+The Company uses derivative financial instruments for price protection purposes on a limited amount
+of its future production and does not use them for trading purposes. Such derivatives are
+accounted for under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative
+Instruments and Hedging Activities” (“SFAS 133”) as amended. See Note 6.
+Income Tax 
+The Company follows the asset and liability method of accounting for deferred income taxes
+prescribed by Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”
+(“SFAS 109”). The statement provides for the recognition of a deferred tax asset for deductible
+temporary timing differences, capital and operating loss carryforwards, statutory depletion
+carryforward and tax credit carryforwards, net of a valuation allowance. The valuation allowance
+is provided for that portion of the asset for which it is deemed more likely than not will not be
+realized. See Note 3.
+Accounts Receivable 
+Accounts receivable consists primarily of accrued oil and gas production receivables. The balance
+in the reserve for doubtful accounts included in accounts receivable was $66,000 and $103,000 at
+December 31, 2005 and 2004, respectively. Net charge offs recorded against the reserve for
+doubtful accounts were $37,000 in 2005 and zero in 2004. There were no provisions to expense in
+the three-year period ended December 31, 2005.
+49
+Table of Contents 
+Accrued Liabilities to be Refinanced 
+Amounts included in accrued liabilities to be refinanced represent capital
+expenditures that were refinanced with the availability
+under the Company’s senior secured credit facility subsequent to the end of the year.
+Major Customers 
+The Company’s production is sold generally on month-to-month contracts at prevailing prices. The
+following table identifies customers to whom it sold a significant percentage of its total oil and
+gas production during each of the years ended:
+December 31, 
+2005 
+2004 
+2003 
+Shell Trading Company 
+34 
+% 
+30 
+% 
+— 
+Louis Dreyfus Energy Services 
+16 
+% 
+23 
+% 
+27 
+% 
+Plains Marketing, L.P. 
+16 
+% 
+13 
+% 
+— 
+Chevron Texaco Natural Gas 
+10 
+% 
+6 
+% 
+— 
+Reliant Energy Services 
+— 
+6 
+% 
+28 
+% 
+Prior Energy Corporation 
+— 
+— 
+20 
+% 
+Because alternative purchasers of oil and gas are readily available, the Company believes that the
+loss of any of these purchasers would not result in a material adverse effect on its ability to
+market future oil and gas production.
+Statements of Cash Flows 
+For purposes of the Consolidated Financial Statements, the Company considers all highly liquid
+investments purchased with an original maturity of three months or less to be cash equivalents.
+The Company paid no federal income taxes for the three years in the period ended December 31, 2005.
+During the years ended December 31, 2005, 2004 and 2003, the Company made cash payments for
+interest of $19,854,000, $23,197,000 and $27,913,000, respectively.
+Accounting Pronouncements 
+On December 16, 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of
+Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”), which
+is a revision of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based
+Compensation” (“SFAS 123”). SFAS 123R supersedes APB Opinion No. 25, Accounting for Stock Issued
+to Employees”, and amends Statement of Financial Accounting Standards No. 95, “Statement of Cash
+Flows.” Generally, the approach in SFAS 123R is similar to the approach described in SFAS 123.
+However, SFAS 123R requires all share-based payments to employees, including grants of employee
+stock options, to be recognized in the income statement based on their fair values. Pro forma
+disclosure is no longer an alternative.
+In April 2005, the Securities and Exchange Commission (“SEC”) delayed the effective date of SFAS
+123R for public companies to no later than the beginning of the first fiscal year beginning after
+June 15, 2005. Early adoption is permitted in periods in which financial statements have not yet
+been issued. SFAS 123R permits public companies to adopt its requirements using one of two methods
+below:
+50
+Table of Contents 
+• 
+A “modified prospective” method in which compensation cost is recognized beginning with
+the effective date (a) based on the requirements of SFAS 123R for all share-based payments
+granted after the effective date and (b) based on the requirements of SFAS 123 for all
+awards granted to employees prior to the effective date of SFAS 123R that remain unvested
+on the effective date; or 
+• 
+A “modified retrospective” method which includes the requirements of the modified
+prospective method described above, but also permits entities to restate based on the
+amounts previously recognized under SFAS 123 for purposes of pro forma disclosures either
+(a) all prior periods presented or (b) prior interim periods of the year of adoption. 
+As permitted by SFAS 123, through December 31, 2005, the Company accounted for share-based payments
+to employees using APB Opinion 25’s intrinsic value method and, as such, generally recognized no
+compensation cost for employee stock options. Accordingly, the adoption of SFAS 123R’s fair value
+method could have a significant impact on our result of operations, although it will have no impact
+on our overall financial position. The impact of SFAS 123R cannot be predicted at this time
+because it will depend on levels of share-based payments granted in the future. However, had we
+adopted SFAS 123R in prior periods, the impact of that standard would have approximated the impact
+of SFAS 123 as described in the disclosure of pro forma net income and earnings per share below
+under “Stock-Based Compensation.” The Company adopted SFAS 123R on January 1, 2006 using the
+modified prospective method.
+Stock-Based Compensation 
+The Company’s pro forma net income (loss) and net income (loss) per share of common stock for the
+years ended December 31, 2005, 2004 and 2003 had compensation costs been recorded using the fair
+value method in accordance with SFAS 123, as amended by Statement of Financial Accounting Standards
+No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure-an amendment of SFAS
+No. 123 (“SFAS 148”), are presented below pursuant to the disclosure requirements of SFAS 148 (in
+thousands except per share data):
+2005 
+2004 
+2003 
+(In thousands, except per share data) 
+Net income (loss) available to common shares,
+as reported 
+$ 
+26,458 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+Stock-based compensation expense included
+in net income as reported, net of tax 
+1,313 
+348 
+17 
+Deduct: Total stock-based
+compensation expense under fair
+value based method, net of tax 
+(1,497 
+) 
+(549 
+) 
+(247 
+) 
+Pro forma net income (loss) available to
+common shares 
+$ 
+26,274 
+$ 
+20,028 
+$ 
+(19,498 
+) 
+Basic
+earnings (loss) per share: As Reported 
+1.43 
+1.28 
+(1.41 
+) 
+Pro Forma 
+1.42 
+1.27 
+(1.43 
+) 
+Diluted earnings (loss) per share: As Reported 
+1.28 
+1.22 
+(1.41 
+) 
+Pro Forma 
+1.27 
+1.20 
+(1.43 
+) 
+See Note 11 for descriptions and additional disclosures related to the stock incentive plans.
+51
+Table of Contents 
+Per Share Amounts 
+Basic income or loss per common share was computed by dividing net income or loss by the weighted
+average number of shares of common stock outstanding during the year. Diluted income or loss per
+common share was determined on a weighted average basis using common shares issued and outstanding
+adjusted for the effect of stock options considered common stock equivalents computed using the
+treasury stock method and the effect of the convertible preferred stock (if dilutive). The
+conversion of the preferred stock was not included in the annual calculation for 2003 due to its
+antidilutive effect on diluted income or loss per common share. In addition, below are the shares
+relating to stock options, warrants and restricted stock that were not included in diluted shares
+for the year ended December 31, 2003 due to the fact that the Company had a loss for this period.
+The Company had net income for the years ended December 31, 2005 and 2004 and all such shares were
+included as described below.
+Twelve Months Ended December 31, 
+(in thousands) 
+2003 
+Stock options 
+63 
+Warrants 
+424 
+Restricted Stock 
+248 
+A reconciliation of the basic and diluted per share computation is as follows (in thousands, except
+per share amounts):
+2005 
+2004 
+2003 
+(a) Net income (loss) available to common shares 
+$ 
+26,458 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+Preferred dividends assuming conversion of
+preferred stock(if dilutive) 
+318 
+1,272 
+— 
+(b) Income
+(loss) available to common shares assuming conversion of
+preferred stock (if dilutive) 
+$ 
+26,776 
+$ 
+21,501 
+$ 
+(19,268 
+) 
+(c) Weighted average shares outstanding 
+18,453 
+15,796 
+13,662 
+Dilutive impact of stock options 
+348 
+233 
+— 
+Dilutive impact of restricted stock 
+69 
+75 
+— 
+Dilutive impact of warrants 
+1,375 
+894 
+— 
+Convertible preferred stock (if dilutive) 
+638 
+680 
+— 
+(d) Total diluted shares 
+20,883 
+17,678 
+13,662 
+Stock options and warrants excluded due to the
+exercise price being greater than the stock price 
+1 
+89 
+2,297 
+Basic income (loss) per share (a ¸ c) 
+$ 
+1.43 
+$ 
+1.28 
+$ 
+(1.41 
+) 
+Diluted income (loss) per share (b ¸ d) 
+$ 
+1.28 
+$ 
+1.22 
+$ 
+(1.41 
+) 
+52
+Table of Contents 
+Fair Value of Financial Instruments 
+Fair value of cash, cash equivalents, accounts receivable, accounts payable, the capital lease and
+the senior secured credit facility approximates book value at December 31, 2005 and 2004. Fair
+value of long-term debt (specifically, the 9.75% Senior Notes) had an estimated fair value of 103%
+of face value at December 31, 2005.
+3. INCOME TAXES 
+The Company had a net current asset of $26.8 million and a net long-term liability of $31.6 million
+resulting in a net deferred tax liability of $4.8 million at December 31, 2005. At December 31,
+2004, the Company had a net current asset of $5.7 million and a net long-term asset of $3.0 million
+resulting in a net deferred tax asset of $8.7 million. Below is an analysis of the net deferred
+tax asset (liability) as of December 31, 2005 and 2004.
+December 31, 
+2005 
+2004 
+(In thousands) 
+Deferred Tax Asset: 
+Federal net operating loss carryforwards 
+$ 
+58,240 
+$ 
+56,271 
+Statutory depletion carryforward 
+4,443 
+4,124 
+Alternative minimum tax credit carryforward 
+547 
+326 
+SFAS 143-Asset Retirement Obligations 
+11,307 
+11,544 
+Other 
+1,389 
+2,786 
+Total deferred tax asset 
+75,926 
+75,051 
+Deferred Tax Liability: 
+Difference between book and tax basis for property 
+(80,565 
+) 
+(66,277 
+) 
+Other 
+(224 
+) 
+(112 
+) 
+Total deferred tax liability 
+(80,789 
+) 
+(66,389 
+) 
+Net deferred tax asset (liability) 
+$ 
+(4,863 
+) 
+$ 
+8,662 
+If not utilized, the Company’s federal net operating loss carryforwards will expire in 2013 through
+2020. The Company has significant state net operating loss carryforwards that are not included in
+the deferred tax asset above, as the Company does not anticipate generating taxable state income in
+the states in which these loss carryforwards apply. The Company has very limited state taxable
+income as primarily all of its revenue is generated in federal waters not subject to state income
+taxes.
+SFAS 109 provides for the weighing of positive and negative evidence in determining whether it is
+more likely than not that a deferred tax asset is recoverable. The Company achieved profitable
+operations in 2005 and 2004 and had income on an aggregate basis for the three-year period ended
+December 31, 2005. In addition, we expect 2006 production levels to meet or exceed 2005 levels. As
+a result, the Company has not provided a valuation allowance as of December 31, 2005.
+53
+Table of Contents 
+The Company incurred losses in 2002 and 2003 and had losses on an aggregate basis for the
+three-year period ended December 31, 2003. Because of these cumulative losses the Company
+established a full valuation allowance of $11.5 million as of December 31, 2003. For the
+three-year period ended December 31, 2004, the Company had income on an aggregate basis resulting
+from the Company achieving profitable operations in 2004 due to the Company’s first two deepwater
+projects starting in November 2003 and the refinancing of the Company’s highest cost debt. As a
+result, the Company reversed the valuation allowance, which had a balance of $7.0 million, as of
+December 31, 2004.
+Below is a reconciliation of the reported amount of income tax expense attributable to continuing
+operations for the year to the amount of income tax expense that would result from applying
+domestic federal statutory tax rates to pretax income from continuing operations.
+Year Ended December 31, 
+2005 
+2004 
+2003 
+Income tax expense (benefit) computed at
+the statutory federal income tax rate 
+35 
+% 
+35 
+% 
+(35 
+%) 
+Change in valuation allowance 
+— 
+(84 
+)% 
+118 
+% 
+Other 
+(1 
+%) 
+— 
+4 
+% 
+Effective income tax rate 
+34 
+% 
+(49 
+)% 
+87 
+% 
+4. OTHER COMPREHENSIVE INCOME 
+The Company’s other comprehensive income (loss) of $1.6 million, $(1.9 million) and $449,000 for
+the years ended December 31, 2005, 2004 and 2003 respectively, relates to the change in fair value
+of its derivatives (other comprehensive income (loss) was net of tax of $835,000, $1.0 million and
+$242,000 for the years ended December 31, 2005, 2004 and 2003, respectively). See Note 6.
+54
+Table of Contents 
+5. LONG-TERM DEBT 
+Long-term debt consisted of the following at:
+December 31, 
+2005 
+2004 
+(In thousands) 
+Senior Secured Credit Facility 
+$ 
+— 
+$ 
+5,000 
+9.75% Senior Notes (due 2010)
+net of discount 
+187,941 
+186,216 
+Capital Lease 
+1,135 
+1,711 
+Total Long-term Debt 
+189,076 
+192,927 
+Less current portion 
+263 
+576 
+Long-term portion 
+$ 
+188,813 
+$ 
+192,351 
+Senior Secured Credit Facility . On June 15, 2004, the Company closed on a three-year senior secured
+credit facility underwritten by Union Bank of California, N.A. (“Union Bank”) to replace the
+Company’s credit facility with Wachovia Bank, National Association (“Wachovia Bank”) which was
+expiring June 30, 2004. The credit facility had an initial borrowing base of $60 million, which was
+increased to $70 million in the second quarter of 2005. The borrowing base is reviewed and
+redetermined semi-annually and can be increased to a maximum of $175 million. Borrowings under the
+credit facility are secured by mortgages covering the Company’s five largest fields. The credit
+facility bears interest at 0.25% above a defined base rate depending on utilization of the
+borrowing base or, at the option of the Company, LIBOR plus 1.5% to 2.25% based on utilization of
+the borrowing base. Under the senior secured credit facility, a commitment fee of 0.25% or 0.375%
+per annum, depending on the amount of the unused portion of the borrowing base, is payable
+quarterly.
+The range of interest rates on the senior secured credit facility was 4.16% to 6.00% for the year
+ended December 31, 2005. The weighted average interest rate for the debt outstanding under the
+senior secured credit facility at December 31, 2004 was 4.16%. As of December 31, 2005 there were
+no borrowings outstanding under the facility; however, Callon had an aggregate of $7.5 million in
+outstanding letters of credit issued under the credit facility. These letters of credit secure
+obligations under the outstanding hedging contracts described in Note 6. The outstanding letters
+of credit reduce the amount available for borrowings under the credit facility. As a result, $62.5
+million was available for future borrowings under the credit facility as of December 31, 2005.
+Certain of the Company’s subsidiaries guarantee the Company’s obligations under the $200 million
+9.75% Senior Notes due 2010. The subsidiary guarantors are 100% owned, all of the guarantees are
+full and unconditional and joint and several, the parent company has no independent assets or
+operations and any subsidiaries of the parent company other than the subsidiary guarantors are
+minor.
+55
+Table of Contents 
+Restructured Debt . In December 2003 and in the first half of 2004, the Company completed several
+transactions which restructured all debt that was maturing through 2005. A summary of these
+transactions is as follows:
+• 
+borrowing $185 million pursuant to a senior unsecured credit facility for a term of
+seven years at an interest rate of 9.75% in December 2003; 
+• 
+the formation of Medusa Spar LLC in which the Company contributed its 15% ownership in
+the deepwater spar production facilities in return for a 10% interest in Medusa Spar LLC
+and approximately $25 million in cash; 
+• 
+borrowing an additional $15 million for a term of seven years at an interest rate of
+9.75% pursuant to a senior unsecured credit agreement in the first quarter of 2004; 
+• 
+closing a three-year senior secured credit facility with an initial borrowing base of
+$60 million in June 2004 which can be increased by the lender to $175 million; and 
+• 
+closing the public offering of 3,450,000 shares of common stock priced at $13.25 per
+share raising net proceeds of approximately $44 million, after expenses, in June 2004. 
+Below is a list of the debt which was extinguished and restructured with the funds raised from the
+transactions above.
+• 
+the Company’s $22.9 million, 10.125% senior subordinated notes due in 2004 
+• 
+the Company’s $40 million, 10.25% senior subordinated notes due in 2004 
+• 
+the Company’s $95 million, 12% senior unsecured credit facility due in 2005 
+• 
+the Company’s $33 million, 11% senior subordinated notes due in 2005 
+All of the above debt was extinguished before maturity which resulted in a loss on early
+extinguishment of debt for the years ended December 31, 2004 and 2003 of $3.0 million and $5.6
+million, respectively. In addition to restructuring the Company’s debt, Callon reduced the balance
+outstanding on its senior secured credit facility.
+9.75% Senior Notes (due 2010). In December 2003 the Company borrowed $185 million pursuant to a
+senior unsecured credit facility. The loans under the credit facility have a stated interest rate
+of 9.75% and a seven-year maturity. The net proceeds of $181.3 million were used to redeem $22.9
+million of 10.125% senior subordinated notes due July 31, 2004, $40 million of 10.25% senior
+subordinated notes due September 15, 2004 and $85 million of our 12% senior loans due March 31,
+2005 plus a 1% pre-payment premium of $850,000, and to reduce the balance outstanding under the
+Company’s senior secured credit facility. In conjunction with the new senior unsecured notes, the
+Company issued detachable warrants to purchase 2.775 million shares of it’s common stock at an
+exercise price of $10 per share and an expiration date of December 2010. The warrants were valued
+at $10.6 million and were treated as a discount on the debt. This senior unsecured debt matures
+December 8, 2010 and has an effective interest rate of 11.4%. The Company recorded the issuance of
+these new securities at a fair value of $171 million. Deferred costs of $14 million associated
+with the notes will be amortized over the life of the notes.
+During March 2004, Callon borrowed an additional $15 million under its 9.75% senior unsecured
+credit facility bringing the total outstanding under the facility to $200 million. The net proceeds
+of approximately $14 million were primarily used to retire the remaining $10 million of 12% senior
+loans due March 31, 2005 plus a 1% call premium of $100,000. The Company recorded the issuance of
+these additional new securities at a fair value of $14 million. Deferred costs of $1 million
+associated with the notes will be amortized over the life of the notes.
+56
+Table of Contents 
+In March 2004, the $200 million in aggregate principal amount of loans outstanding under the 9.75%
+senior unsecured credit facility were exchanged for 9.75% Senior Notes due 2010, Series A, “Series
+A notes”, issued pursuant to a senior indenture between Callon and American Stock Transfer & Trust
+Company dated March 15, 2004. On August 12, 2004, the Company completed an offer to exchange its
+9.75% Senior Notes due 2010, Series B, that have been registered under the Securities Act of 1933,
+for all outstanding Series A notes.
+In December 2005, 79,500 of the detachable warrants issued with the 9.75% Senior Notes due 2010
+were exercised. In addition, 265,210 of $0.01 warrants associated with the 12% senior unsecured
+credit facility due in 2005 were outstanding as of December 31, 2005.
+Capital Lease . In December 2001, the Company entered into a 10-year gas processing agreement
+associated with a production facility on Callon’s Mobile Block 952 Field with Hanover Compression
+Limited Partnership, which is being accounted for as a capital lease. Total minimum obligations
+are $8.4 million with interest representing approximately $2.8 million and the present value
+minimum obligations representing $5.6 million.
+Restrictive Covenants . The Indenture governing our 9.75% senior notes due 2010 and our senior
+secured credit facility contains various covenants including restrictions on additional
+indebtedness and payment of cash dividends. In addition, our senior secured credit facility
+contains covenants for maintenance of certain financial ratios. The Company was in compliance with
+these covenants at December 31, 2005.
+Future minimum lease payments and debt maturities (in thousands) are as follows:
+Capital Lease 
+Year 
+Payments 
+Debt 
+2006 
+$ 
+439 
+$ 
+— 
+2007 
+348 
+— 
+2008 
+228 
+— 
+2009 
+229 
+— 
+2010 
+220 
+200,000 
+Thereafter 
+245 
+— 
+57
+Table of Contents 
+6. DERIVATIVES 
+The Company periodically uses derivative financial instruments to manage oil and gas price risk.
+Settlements of gains and losses on commodity price contracts are generally based upon the
+difference between the contract price or prices specified in the derivative instrument and a NYMEX
+price or other cash or futures index price.
+The Company’s derivative contracts that are accounted for as cash flow hedges under SFAS 133 are
+recorded at fair market value and the changes in fair value are recorded through other
+comprehensive income (loss), net of tax, in stockholders’ equity. The cash settlements on these
+contracts are recorded as an increase or decrease in oil and gas sales. The changes in fair value
+related to ineffective derivative contracts are recognized as derivative expense (income). The
+cash settlement on these contracts is also recorded within derivative expense (income). The
+changes in fair value of the Company’s derivative contracts that are not designated as effective
+cash flow hedges are recorded through the statement of operations as derivative expense (income).
+Cash settlements on effective cash flow hedges for the years ended December 31, 2005, 2004 and 2003
+resulted in a reduction of oil and gas sales in the amount of $10.3 million, $13.8 million and $2.9
+million, respectively. Cash settlements on ineffective derivative contracts were recorded as
+derivative expense in the amount of $4.4 million and $1.2 million for the years ended December 31,
+2005 and 2004, respectively. These contracts were deemed ineffective as a result of a shortfall in
+production volumes due to downtime from the tropical storm activity in the third quarters of 2005
+and 2004 impacting third and fourth quarter production volumes for the respective years.
+The following table summarizes derivative expense for the periods presented (in thousands):
+December 31, 
+2005 
+2004 
+2003 
+Amortization of derivative contract premiums 
+$ 
+1,634 
+$ 
+— 
+$ 
+— 
+Change in fair value and settlements of ineffective
+derivative contracts 
+4,394 
+1,209 
+— 
+Change in fair value and settlements of
+non-designated
+derivative contracts 
+— 
+162 
+535 
+$ 
+6,028 
+$ 
+1,371 
+$ 
+535 
+58
+Table of Contents 
+The Company had a current liability of $1.2 million and a current asset of $889,000 relating to the
+fair value of its respective derivative contracts as of December 31, 2005.
+Listed in the table below are the outstanding derivative contracts as of December 31, 2005:
+Swaps 
+Volumes per 
+Quantity 
+Average 
+Product 
+Month 
+Type 
+Price 
+Period 
+Oil 
+15,000 
+Bbls 
+$ 
+55.00 
+01/06-06/06 
+Collars 
+Average 
+Average 
+Volumes per 
+Quantity 
+Floor 
+Ceiling 
+Product 
+Month 
+Type 
+Price 
+Price 
+Period 
+Oil 
+30,000 
+Bbls 
+$ 
+60.00 
+$ 
+77.10 
+01/06-12/06 
+Natural Gas 
+200,000 
+MMBtu 
+$ 
+10.00 
+$ 
+16.00 
+01/06-03/06 
+Natural Gas 
+100,000 
+MMBtu 
+$ 
+8.33 
+$ 
+11.93 
+01/06-09/06 
+7. COMMITMENTS AND CONTINGENCIES 
+From time to time, the Company, as part of the Consolidation and other capital transactions,
+entered into registration rights agreements whereby certain parties to the transactions are
+entitled to require the Company to register common stock of the Company owned by them with the
+Securities and Exchange Commission for sale to the public in firm commitment public offerings and
+generally to include shares owned by them, at no cost, in registration statements filed by the
+Company. Costs of the offering will not include broker’s discounts and commissions, which will be
+paid by the respective sellers of the common stock.
+The Company is involved in various claims and lawsuits incidental to its business. In the opinion
+of management, the ultimate liability thereunder, if any, will not have a material adverse effect
+on the financial position or results of operations of the Company.
+The Company’s Medusa deepwater property is eligible for royalty suspensions pursuant to the Deep
+Water Royalty Relief Act. In addition, the Company has several shallow water, deep natural gas
+properties and prospects that are eligible for royalty suspensions. However, the federal offshore
+leases covering these properties contain “price threshold” provisions for oil and gas prices.
+Under these “price threshold” provisions, if the average monthly New York Mercantile Exchange
+(NYMEX) sales price for oil or gas during a fiscal year exceeds the price threshold for oil or gas,
+respectively, then royalties on the associated production must be paid to the Minerals Management
+Service (MMS) at the rate stipulated in the lease. The price thresholds are adjusted annually by
+the implicit price deflator for the GDP. The determination of whether or not royalties are due as
+a result of the average NYMEX price exceeding the price threshold is made during the first quarter
+of the succeeding year. Any royalty payments due must be made shortly after this determination is
+made. If a royalty payment is due for all production during a year as a result of exceeding the
+price threshold, the lessee is required to make monthly royalty payments during the succeeding
+fiscal year for the succeeding year’s production. If at the end of any year the average NYMEX
+price is below the price threshold, the lessee can apply for a refund for any associated royalties
+paid during that year and the lessee will not be required to pay royalties monthly during the
+succeeding year for the succeeding year’s production.
+59
+Table of Contents 
+The thresholds and actual average NYMEX for 2005 are in the table below.
+2005 
+Actual Average 
+Threshold 
+NYMEX 
+Deepwater Oil Prices ($/bbl) 
+34.73 
+56.57 
+Deepwater Natural Gas Prices ($/mmbtu) 
+4.34 
+8.96 
+Shallow Water, Deep Natural Gas
+Prices ($/mmbtu) 
+9.60 
+8.96 
+The Company was required to make monthly royalty payments for 2005 deepwater oil and gas production
+and will be required to make monthly royalty payments for 2006. With regard to the shallow water,
+deep natural gas royalty relief, the Company will not be required to make monthly royalty payments
+for 2006.
+In the year succeeding the year in which any of the Company’s properties became subject to
+royalties as the result of the average NYMEX price exceeding the price threshold, the portion of
+reserves attributable to potential future royalties would not be included in a year-end reserve
+report. However, if the average NYMEX prices were below the price thresholds in subsequent years,
+our reserves would be increased to reflect reserves previously attributed to future royalties. As
+a result, reported oil and gas reserves could materially increase or decrease, depending on the
+relation of price thresholds versus the average NYMEX prices. The reduction in revenues resulting
+from an obligation to pay these royalties and subsequent reduction of proved reserves could have a
+material adverse effect on the Company’s results of operations and financial condition. The
+Company’s reserve report as of December 31, 2005 excluded oil and gas reserves for Medusa that are
+subject to MMS royalties as a result of the average 2005 NYMEX prices for oil and gas exceeding the
+price thresholds.
+The Company’s activities are subject to federal, state and local laws and regulations governing
+environmental quality and pollution control. Although no assurances can be made, the Company
+believes that, absent the occurrence of an extraordinary event, compliance with existing federal,
+state and local laws, rules and regulating the release of materials in the environment or otherwise
+relating to the protection of the environment will not have a material effect upon the capital
+expenditures, earnings or the competitive position of the Company with respect to its existing
+assets and operations. The Company cannot predict what effect additional regulation or
+legislation, enforcement polices thereunder, and claims for damages to property, employees, other
+persons and the environment resulting from the Company’s operations could have on its activities.
+8. ASSET RETIREMENT OBLIGATIONS 
+As discussed in Note 2, the Company adopted SFAS 143 on January 1, 2003. The impact of adopting
+the statement resulted in a gain of $181,000, net of tax, which was reported as a cumulative effect
+of change in accounting principle.
+Approximately $30.3 million was recorded as the present value of asset retirement obligations on
+January 1, 2003 with the adoption of SFAS 143 related to the Company’s oil and gas properties.
+Interest is accreted on this amount and reported as accretion expense in the Consolidated
+Statements of Operations.
+60
+Table of Contents 
+Assets, primarily short-term U.S. Government securities, of approximately $6.0 million at December
+31, 2005, of which $4.1 million was current, was recorded as restricted investments. These assets
+are held in abandonment trusts (“Trusts”) dedicated to pay future abandonment costs of oil and gas
+properties in which the Company has sold a net profit interest (“NPI”). In September 2005, Callon
+purchased the NPI’s
+which included the Trusts. See Note 10 to the Consolidated Financial Statements for more detail on
+the NPI transaction.
+The following table summarizes the activity for the Company’s asset retirement obligations:
+Twelve Months Ended 
+December 31, 2005 
+December 31, 2004 
+Asset retirement obligations at
+beginning of period 
+$ 
+38,282 
+$ 
+33,691 
+Accretion expense 
+3,549 
+3,400 
+Net profits interest accretion 
+331 
+459 
+Liabilities incurred 
+2,365 
+3,065 
+Liabilities settled 
+(5,184 
+) 
+(2,076 
+) 
+Revisions to estimate 
+(1,070 
+) 
+(257 
+) 
+Asset retirement obligation at end of period 
+38,273 
+38,282 
+Less: current retirement obligations 
+(21,660 
+) 
+(13,300 
+) 
+Long-term retirement obligations 
+$ 
+16,613 
+$ 
+24,982 
+61
+Table of Contents 
+9. OIL AND GAS PROPERTIES 
+The following table discloses certain financial data relating to the Company’s oil and gas
+activities, all of which are located in the United States.
+Years Ended December 31, 
+2005 
+2004 
+2003 
+(In thousands) 
+Capitalized costs incurred: 
+Evaluated Properties- 
+Beginning of period balance 
+$ 
+862,101 
+$ 
+802,912 
+$ 
+762,918 
+Property acquisition costs 
+6,627 
+1,355 
+1,154 
+Exploration costs 
+46,379 
+26,749 
+21,390 
+Development costs 
+26,481 
+32,004 
+33,972 
+SFAS 143-Asset Retirement Obligation 
+(3,890 
+) 
+(918 
+) 
+18,002 
+Medusa Spar transaction 
+— 
+— 
+(33,542 
+) 
+Sale of mineral interests 
+— 
+(1 
+) 
+(982 
+) 
+End of period balance 
+$ 
+937,698 
+$ 
+862,101 
+$ 
+802,912 
+Unevaluated Properties (excluded from
+amortization) - 
+Beginning of period balance 
+$ 
+39,042 
+$ 
+34,251 
+$ 
+40,997 
+Additions 
+18,739 
+16,367 
+5,228 
+Capitalized interest 
+5,655 
+4,577 
+4,862 
+Transfers to evaluated 
+(14,371 
+) 
+(16,153 
+) 
+(16,836 
+) 
+End of period balance 
+$ 
+49,065 
+$ 
+39,042 
+$ 
+34,251 
+Accumulated depreciation, depletion
+and amortization- 
+Beginning of period balance 
+$ 
+494,453 
+$ 
+447,000 
+$ 
+426,254 
+Provision charged to expense 
+44,946 
+47,453 
+28,195 
+Cumulative effect of change in accounting
+Principle 
+— 
+— 
+(7,449 
+) 
+End of period balance 
+$ 
+539,399 
+$ 
+494,453 
+$ 
+447,000 
+Unevaluated property costs, primarily lease acquisition costs incurred at federal and state lease
+sales, unevaluated drilling costs, capitalized interest and general and administrative costs being
+excluded from the amortizable evaluated property base, consisted of $18.8 million incurred in 2005,
+$7.8 million incurred in 2004 and $22.5 million incurred in 2003 and prior. These costs are
+directly related to the acquisition and evaluation of unproved properties and major development
+projects. The excluded costs and related reserves are included in the amortization base as the
+properties are evaluated and proved reserves are established or impairment is determined. The
+Company expects that the majority of these costs will be evaluated over the next three to five-year
+period.
+Depletion per unit-of-production (thousand cubic feet of gas equivalent) amounted to $2.39, $2.18
+and $2.03 for the years ended December 31, 2005, 2004, and 2003, respectively.
+62
+Table of Contents 
+Under the full-cost accounting rules of the SEC, the Company reviews the carrying value of its
+proved oil and gas properties each quarter. Under these rules, capitalized costs of proved oil and
+gas properties net of accumulated depreciation, depletion and amortization (DD&A) and deferred
+income taxes, may not exceed the
+present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10
+percent, plus the lower of cost or fair value of unproved properties net of related tax effects.
+These rules generally require pricing future oil and gas production at the unescalated market price
+for oil and gas at the end of each fiscal quarter and require a write-down if the “ceiling” is
+exceeded, unless prices recover sufficiently subsequent to the balance sheet date before the
+release of the financial statements. Given the volatility of oil and gas prices, it is reasonably
+possible that the Company’s estimate of discounted future net cash flows from proved oil and gas
+reserves could change in the near term. If oil and gas prices decline significantly, even if only
+for a short period of time, it is possible that writedowns of oil and gas properties could occur in
+the future.
+10. NET PROFITS INTEREST 
+From 1989 through 1994, the Constituent Entities entered into separate agreements to purchase
+certain oil and gas properties with gross contract acquisition prices of $170,000,000 ($150,000,000
+net as of closing dates) and in simultaneous transactions, entered into agreements to sell
+overriding royalty interests (“ORRI”) in the acquired properties. These ORRI were in the form of
+NPI’s equal to a significant percentage of the excess of gross proceeds over costs, as defined by
+the agreements, from the acquired oil and gas properties. In September 2005, the Company purchased
+the NPI’s for $5 million before intervening operations. Included in the transaction were the
+Trusts which were established at the inception of the NPI’s for future plugging and abandonment
+liabilities.
+The Company, pursuant to the purchase agreements, created the Trusts (see Note 8) whereby funds are
+provided out of gross production proceeds from the properties for the estimated amount of future
+abandonment obligations related to the working interests owned by the Company. The Trusts are
+administered by unrelated third party trustees for the benefit of the Company’s working interest in
+each property. The Trust agreements limit disbursement of funds to the satisfaction of abandonment
+obligations. Any funds remaining in the Trusts after all restoration, dismantlement and
+abandonment obligations have been met will be distributed to Callon. Estimated future revenues and
+costs associated with the Trusts are also excluded from the oil and gas reserve disclosures at Note
+13. As of December 31, 2005 and 2004, the Trusts’ assets (all cash and investments) totaled $6.0
+million and $7.7 million respectively, all of which will be available to the Company to pay the
+restoration, dismantlement and abandonment costs. SFAS 143, discussed in Note 2 and 8, does not
+allow the Trusts’ assets to be used to offset the associated abandonment liability. The Company did
+not record any income or loss associated with the Trust asset or abandonment liability as a result
+of adoption of SFAS 143.
+63
+Table of Contents 
+11. EMPLOYEE BENEFIT PLANS 
+The Company has adopted a series of incentive compensation plans designed to align the interest of
+the executives and employees with those of its stockholders. The following is a brief description
+of each plan:
+Savings and Protection Plan 
+The Savings and Protection Plan (“401-K Plan”) provides employees with the
+option to defer receipt of a portion of their compensation and the Company may, at
+its discretion, match a portion of the employee’s deferral with cash and Company
+Common Stock. The Company may also elect, at its discretion, to contribute a
+non-matching amount in cash and Company Common Stock to employees. The amounts held
+under the 401-K Plan are invested in various funds maintained by a third party in
+accordance with the directions of each employee. An employee is fully vested,
+including Company discretionary contributions, immediately upon participation in the
+401-K Plan. The total amounts contributed by the Company, including the value of
+the common stock contributed, were $557,000, $528,000 and $562,000 in the years
+2005, 2004 and 2003, respectively.
+1994 Stock Incentive Plan 
+The 1994 Stock Incentive Plan (the “1994 Plan”), approved by the shareholders
+in 1994, provides for 600,000 shares of Common Stock to be reserved for issuance
+pursuant to such plan. Under the 1994 Plan, the Company may grant both stock
+options qualifying under Section 422 of the Internal Revenue Code and options that
+are not qualified as incentive stock options, as well as performance shares. These
+options have an expiration date of 10 years from the date of grant.
+1996 Stock Incentive Plan 
+On August 23, 1996, the Board of Directors of the Company approved and adopted
+the Callon Petroleum Company 1996 Stock Incentive Plan (the “1996 Plan”). The 1996
+Plan was approved by the shareholders in 1997 and provides for the same types of
+awards as the 1994 Plan and is limited to a maximum of 1,200,000 shares (as amended
+from the original 900,000 shares) of common stock that may be subject to outstanding
+awards. Unvested options are subject to forfeiture upon certain termination of
+employment events and expire 10 years from the date of grant.
+The Company granted 533,000 stock options to employees on March 23, 2000 and
+120,000 stock options to directors on July 25, 2000 at $10.50 per share. The March
+23, 2000 grant was subject to shareholder approval of an amendment to the 1996 Stock
+Incentive Plan. The amendment, which was approved on May 9, 2000 at the Annual
+Meeting of Shareholders, increased the number of shares reserved for issuance under
+the 1996 plan to 2,200,000 shares. The excess of the market price over the exercise
+price on the approval date of the amendment was amortized over the three-year
+vesting period of the options. Compensation costs of $27,000 were recognized in
+2003, related to these options.
+64
+Table of Contents 
+In 2004, the Company awarded 455,000 performance shares from the 1994 and 1996
+Plans. These shares vest to the recipients over a five-year period (one-fifth in
+each year) beginning in July 2005. The deferred compensation portion of this grant
+will be amortized to expense over the vesting period. The non-cash amortization
+expense in 2005 and 2004 was $1,029,000 and $532,000, respectively. In 2005, an additional non-cash expense of $989,000 was
+recognized for accelerated vesting of performance shares for an executive officer
+and two directors of the Company, two of whom are deceased, and the retirement of an
+employee.
+2002 Stock Incentive Plan 
+On February 14, 2002, the Board of Directors of the Company approved and adopted
+the 2002 Stock Incentive Plan (the “2002 Plan”). Pursuant to the 2002 Plan, 350,000
+shares of common stock shall be reserved for issuance upon the exercise of options or
+for grants of stock options, stock appreciation rights or units, bonus stock, or
+performance shares or units. This Plan qualified as a “broadly based” plan under the
+provisions of the New York Stock Exchange’s rules and regulations and therefore did
+not require shareholder approval. Because the 2002 Plan is a broadly based plan, the
+aggregate number of shares underlying awards granted to officers and directors cannot
+exceed 50% of the total number of shares underlying the awards granted to all
+employees during any three-year period.
+In 2002, the Company awarded 300,000 shares of restricted stock from the 1996 and the
+2002 Plan and 70,500 from treasury shares to be issued as vested. The issuance of
+the restricted stock using treasury shares did not require shareholder approval
+pursuant to the New York Stock Exchange’s rules and regulations, and therefore
+shareholder approval was not sought. These shares vested to the recipients over a
+three-year period (one-third in each year) beginning in November 2002. The deferred
+compensation portion of this grant was amortized to expense over the vesting period.
+The non-cash amortization expense in 2004 and 2003 was $374,000 and $454,000,
+respectively.
+Employee Stock Purchase Plan 
+In 1997, the Board of Directors authorized the implementation of the Callon Petroleum
+Company 1997 Employee Stock Purchase Plan (the “1997 ESPP”), which was approved by
+the Company’s shareholders at the 1997 Annual Meeting. The 1997 ESPP provided
+eligible employees of the Company with the opportunity to acquire a proprietary
+interest in the Company through participation in a payroll deduction-based employee
+stock purchase plan. An aggregate of 250,000 shares of common stock were reserved
+for issuance over the10-year term of the 1997 ESPP. The purchase price per share at
+which common stock was purchased on the participant’s behalf on each purchase date
+within an offering period was equal to 85 percent of the fair market value per share
+of common stock. As of December 31, 2004 there were no remaining shares available
+for purchase.
+65
+Table of Contents 
+A summary of the status of the Company’s stock option plans for the three most recent years and
+changes during the years then ended is presented in the table and narrative below:
+2005 
+2004 
+2003 
+Wtd Avg 
+Wtd Avg 
+Wtd Avg 
+Shares 
+Ex Price 
+Shares 
+Ex Price 
+Shares 
+Ex Price 
+Outstanding, beginning of year 
+1,512,599 
+$ 
+9.93 
+2,450,867 
+$ 
+9.84 
+2,520,417 
+$ 
+9.90 
+Granted (at market) 
+65,000 
+15.79 
+25,000 
+12.40 
+30,000 
+5.12 
+Exercised 
+(329,441 
+) 
+10.34 
+(437,918 
+) 
+9.74 
+(500 
+) 
+4.10 
+Forfeited 
+— 
+— 
+(525,350 
+) 
+9.80 
+(99,050 
+) 
+9.74 
+Expired 
+(42,600 
+) 
+10.60 
+— 
+— 
+— 
+— 
+Outstanding, end of year 
+1,205,558 
+$ 
+10.11 
+1,512,599 
+$ 
+9.93 
+2,450,867 
+$ 
+9.84 
+Exercisable, end of year 
+1,166,558 
+$ 
+9.88 
+1,446,486 
+$ 
+10.20 
+2,262,067 
+$ 
+10.31 
+Weighted average fair value of
+options granted (at market) 
+$ 
+5.93 
+$ 
+4.48 
+$ 
+2.97 
+The following table sets forth additional information regarding options outstanding at
+December 31, 2005. Contractual life and exercise prices represent weighted averages for options
+outstanding and options exercisable.
+Options Outstanding 
+Options Exercisable 
+Range of 
+Number 
+Contractual 
+Exercise 
+Number 
+Exercise 
+exercise prices 
+Outstanding 
+Life (years) 
+Price 
+Exercisable 
+Price 
+$3.70 to $6.41 
+185,308 
+6.6 
+$ 
+4.48 
+185,308 
+$ 
+4.48 
+$9.00 to $12.40 
+905,250 
+3.1 
+$ 
+10.64 
+905,250 
+$ 
+10.64 
+$13.56 to $19.72 
+115,000 
+6.4 
+$ 
+15.67 
+76,000 
+$ 
+14.11 
+The fair value of each option grant is estimated on the date of grant using the Black-Scholes
+option pricing model with the following weighted average assumptions used for options granted
+during the years presented are as follows:
+2005 
+2004 
+2003 
+Risk free interest rate 
+4.3 
+% 
+3.7 
+% 
+4.0 
+% 
+Expected life (years) 
+4.5 
+5.0 
+5.0 
+Expected volatility 
+37.5 
+% 
+45.1 
+% 
+65.3 
+% 
+Expected dividends 
+— 
+— 
+— 
+66
+Table of Contents 
+12. EQUITY TRANSACTIONS 
+On June 13, 2005, Callon called for redemption all of the Company’s outstanding shares of $2.125
+Convertible Exchange Preferred Stock, Series A. A notice of redemption and letter of transmittal
+was mailed to all holders of record as of the close of business on June 10, 2005. Between June 13,
+2005 and June 30, 2005, 180,173 shares of preferred stock were converted into 409,496 shares of the Company’s common stock.
+Subsequent to June 30, 2005, 392,935 shares of preferred stock were converted into 893,076 shares
+of the Company’s common stock. In addition, 23,563 shares of the Company’s preferred stock were
+redeemed for $606,000 on July 14, 2005. As a result of the redemption, we will benefit from an
+annual cash savings of $1.3 million in dividend payments.
+On June 22, 2004, we closed the public offering of three million shares of common stock priced at
+$13.25 per share raising net proceeds of approximately $38.2 million, after expenses. In addition,
+we granted the underwriter, Johnson Rice & Company L.L.C., an over-allotment option to purchase an
+additional 450,000 shares. On June 30, 2004, the underwriter exercised the over-allotment option
+for an additional 450,000 shares priced at $13.25 per share, raising the net proceeds of the
+offering by approximately $5.7 million, after expenses. The proceeds from the transactions were
+used to redeem $33 million of the 11% Senior Subordinated Notes due December 15, 2005 and for
+general corporate purposes.
+The Company adopted a stockholder rights plan on March 30, 2000, designed to assure that the
+Company’s stockholders receive fair and equal treatment in the event of any proposed takeover of
+the Company and to guard against partial tender offers, squeeze-outs, open market accumulations,
+and other abusive tactics to gain control without paying all stockholders a fair price. The rights
+plan was not adopted in response to any specific takeover proposal. Under the rights plan, the
+Company declared a dividend of one right (“Right”) on each share of the Company’s Common Stock.
+Each Right will entitle the holder to purchase one one-thousandth of a share of a Series B
+Preferred Stock, par value $0.01 per share, at an exercise price of $90 per one one-thousandth of a
+share.
+The Rights are not currently exercisable and will become exercisable only in the event a person or
+group acquires, or engages in a tender or exchange offer to acquire, beneficial ownership of 15
+percent or more (one existing stockholder was granted an exception for up to 21 percent) of the
+Company’s Common Stock. After the Rights become exercisable, each Right will also entitle its
+holder to purchase a number of common shares of the Company having a market value of twice the
+exercise price. The dividend distribution was made to stockholders of record at the close of
+business on April 10, 2000. The Rights will expire on March 30, 2010.
+13. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED) 
+The Company’s proved oil and gas reserves at December 31, 2005, 2004 and 2003 have been estimated
+by Huddleston & Co., Inc. who are the Company’s independent petroleum consultants. The reserves
+were prepared in accordance with guidelines established by the Securities and Exchange Commission
+(“SEC”). Accordingly, the following reserve estimates are based upon existing economic and
+operating conditions.
+There are numerous uncertainties inherent in establishing quantities of proved reserves. The
+following reserve data represents estimates only and should not be construed as being exact. In
+addition, the standardized measure of discounted future net cash flows should not be construed as
+the current market value of the Company’s oil and gas properties or the cost that would be incurred
+to obtain equivalent reserves. See Note 7 regarding the Deep Water Royalty Relief Act and the loss
+of reserves.
+67
+Table of Contents 
+Estimated Reserves 
+Changes in the estimated net quantities of crude oil and natural gas reserves, all of which are
+located onshore and offshore in the continental United States, are as follows:
+Reserve Quantities 
+Years Ended December 31, 
+2005 
+2004 
+2003 
+Proved developed and undeveloped reserves: 
+Crude Oil (MBbls): 
+Beginning of period 
+19,748 
+23,709 
+24,043 
+Revisions to previous estimates 
+316 
+(2,370 
+)(a) 
+(1 
+) 
+Purchase of reserves in place 
+71 
+— 
+— 
+Sales of reserves in place 
+— 
+— 
+(65 
+) 
+Extensions and discoveries 
+129 
+145 
+— 
+Production 
+(1,836 
+) 
+(1,736 
+) 
+(268 
+) 
+End of period 
+18,428 
+19,748 
+23,709 
+Natural Gas (MMcf): 
+Beginning of period 
+72,619 
+74,691 
+91,539 
+Revisions to previous estimates 
+(4,946 
+) 
+2,138 
+(6,407 
+)(a) 
+Purchase of reserves in place 
+1,308 
+— 
+— 
+Sales of reserves in place 
+— 
+— 
+(49 
+) 
+Extensions and discoveries 
+16,808 
+7,177 
+1,923 
+Production 
+(7,768 
+) 
+(11,387 
+) 
+(12,315 
+) 
+End of period 
+78,021 
+72,619 
+74,691 
+Proved developed reserves: 
+Crude Oil (MBbls): 
+Beginning of period 
+10,292 
+9,919 
+1,056 
+End of period 
+7,323 
+10,292 
+9,919 
+Natural Gas (MMcf): 
+Beginning of period 
+33,982 
+31,415 
+37,631 
+End of period 
+30,982 
+33,982 
+31,415 
+(a) 
+Includes Medusa royalty adjustment 
+68
+Table of Contents 
+Standardized Measure 
+The following tables present the Company’s standardized measure of discounted future net cash flows
+and changes therein relating to proved oil and gas reserves and were computed using reserve
+valuations based on regulations prescribed by the SEC. These regulations provide that the oil,
+condensate and gas price structure utilized to project future net cash flows reflects current
+prices (approximately $10.13 per Mcf for natural gas and $55.44 per Bbl for oil for the 2005
+disclosures, $6.51 per Mcf and $36.72 per Bbl for 2004
+disclosures, and $5.99 per Mcf and $30.50 per Bbl for 2003 disclosures) at each date presented and
+have not been escalated. Future production and development costs are based on current costs
+without escalation. The resulting net future cash flows have been discounted to their present
+values based on a 10% annual discount factor.
+Standardized Measure 
+Years Ended December 31, 
+2005 
+2004 
+2003 
+(In thousands) 
+Future cash inflows 
+$ 
+1,814,208 
+$ 
+1,198,096 
+$ 
+1,170,118 
+Future costs — 
+Production 
+(238,321 
+) 
+(231,616 
+) 
+(219,421 
+) 
+Development and net abandonment 
+(88,070 
+) 
+(74,335 
+) 
+(111,850 
+) 
+Future net inflows before income taxes 
+1,487,817 
+892,145 
+838,847 
+Future income taxes 
+(379,287 
+) 
+(166,284 
+) 
+(89,567 
+) 
+Future net cash flows 
+1,108,530 
+725,861 
+749,280 
+10% discount factor 
+(270,978 
+) 
+(209,968 
+) 
+(230,254 
+) 
+Standardized measure of discounted
+future net cash flows 
+$ 
+837,552 
+$ 
+515,893 
+$ 
+519,026 
+Changes in Standardized Measure 
+Years Ended December 31, 
+2005 
+2004 
+2003 
+(In thousands) 
+Standardized
+measure — beginning of period 
+$ 
+515,893 
+$ 
+519,026 
+$ 
+556,046 
+Sales and transfers, net of production costs 
+(116,913 
+) 
+(97,494 
+) 
+(62,396 
+) 
+Net change in sales and transfer prices,
+net of production costs 
+391,570 
+86,551 
+(41,011 
+) 
+Exchange and sale of in place reserves 
+— 
+— 
+(1,226 
+) 
+Purchases, extensions, discoveries, and
+improved
+recovery, net of future production and
+development costs incurred 
+127,848 
+77,576 
+25,632 
+Revisions of quantity estimates 
+(17,241 
+) 
+(41,314 
+) 
+(18,018 
+) 
+Accretion of discount 
+61,259 
+57,046 
+62,394 
+Net change in income taxes 
+(154,460 
+) 
+(45,262 
+) 
+16,460 
+Changes in production rates, timing and other 
+29,596 
+(40,236 
+) 
+(18,855 
+) 
+Standardized measure — end of period 
+$ 
+837,552 
+$ 
+515,893 
+$ 
+519,026 
+69
+Table of Contents 
+14. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) 
+First 
+Second 
+Third 
+Fourth 
+2005 
+Quarter 
+Quarter 
+Quarter(a) 
+Quarter(a) 
+(In thousands, except per share data) 
+Total revenues 
+$ 
+43,012 
+$ 
+41,668 
+$ 
+31,722 
+$ 
+24,888 
+Income from operations 
+18,134 
+17,696 
+8,692 
+9,783 
+Net income 
+9,475 
+9,311 
+3,683 
+4,307 
+Net income
+per common share — basic 
+$ 
+0.52 
+$ 
+0.52 
+$ 
+0.19 
+$ 
+0.22 
+Net income
+per common share — diluted 
+0.46 
+0.46 
+0.17 
+0.20 
+First 
+Second 
+Third 
+Fourth 
+2004 
+Quarter 
+Quarter 
+Quarter 
+Quarter 
+(In thousands, except per share data) 
+Total revenues 
+$ 
+31,919 
+$ 
+37,606 
+$ 
+25,138 
+$ 
+25,139 
+Income from operations 
+10,231 
+14,543 
+5,367 
+6,371 
+Net income 
+2,102 
+9,730 
+546 
+9,123 
+(b) 
+Net income per common share-basic 
+$ 
+0.13 
+$ 
+0.66 
+$ 
+0.01 
+$ 
+0.50 
+(b) 
+Net income per common share-diluted 
+0.12 
+0.58 
+0.01 
+0.45 
+(b) 
+(a) 
+These quarters were impacted by tropical storm and hurricane activity. 
+(b) 
+The fourth quarter of 2004 includes a tax benefit of $6.7 million resulting from the
+elimination of the valuation allowance established in 2003. See Note 3. 
+70
+Table of Contents 
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
+ACCOUNTING AND FINANCIAL DISCLOSURE 
+There have been no disagreements with the independent auditors on any matters of accounting
+principles or practices, financial statement disclosure, or auditing scope or procedures.
+ITEM 9.A CONTROLS AND PROCEDURES 
+The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the
+Securities Exchange Act of 1934, or the Exchange Act. This term refers to the controls and
+procedures of a company that are designed to ensure that information required to be disclosed by a
+company in the reports that it files or submits under the Exchange Act is recorded, processed,
+summarized and reported within the time periods specified by the Securities and Exchange
+Commission. Our management, including our Chief Executive Officer, has evaluated the effectiveness
+of our disclosure controls and procedures as of the end of the period covered by this annual
+report. Based upon that evaluation, our Chief Executive Officer has concluded that our disclosure
+controls and procedures were effective as of the end of the period covered by this annual report.
+There were no changes to our internal control over financial reporting during our last fiscal
+quarter that have materially affected, or are reasonable likely to materially affect, our internal
+control over financial reporting.
+Management’s Report On Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over
+financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the
+supervision and with the participation of our management, including our principal executive and
+financial officer, we conducted an evaluation of the effectiveness of our internal control over
+financial reporting as of December 31, 2005 based on the frame work in the Internal
+Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
+Commission. Based on our evaluation under the framework in Internal Control-Integrated Framework,
+our management concluded that our internal control over financial reporting was effective as of
+December 31, 2005.
+Ernst & Young LLP, our independent registered public accounting firm, has issued an attestation
+report on our management’s assessment of the effectiveness of our internal control over financial
+reporting which is included herein.
+71
+Table of Contents 
+Report of Independent Registered Public Accounting Firm
+The Stockholders and Board of Directors 
+Callon Petroleum Company
+We have audited management’s assessment, included in the accompanying Management’s Report on
+Internal Control over Financial Reporting, that Callon Petroleum Company maintained effective
+internal control over financial reporting as of December 31, 2005, based on criteria established in
+Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the
+Treadway Commission (COSO). Callon Petroleum Company’s management is responsible for
+maintaining effective internal control over financial reporting and for its assessment of the
+effectiveness of internal control over financial reporting. Our responsibility is to express an
+opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal
+control over financial reporting based on our audit.
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
+Board (United States). Those standards require that we plan and perform the audit to obtain
+reasonable assurance about whether effective internal control over financial reporting was
+maintained in all material respects. Our audit included obtaining an understanding of internal
+control over financial reporting, evaluating management’s assessment, testing and evaluating the
+design and operating effectiveness of internal control, and performing such other procedures as we
+considered necessary in the circumstances. We believe that our audit provides a reasonable basis
+for our opinion.
+A company’s internal control over financial reporting is a process designed to provide reasonable
+assurance regarding the reliability of financial reporting and the preparation of financial
+statements for external purposes in accordance with generally accepted accounting principles. A
+company’s internal control over financial reporting includes those policies and procedures that (1)
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
+transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
+transactions are recorded as necessary to permit preparation of financial statements in accordance
+with generally accepted accounting principles, and that receipts and expenditures of the company
+are being made only in accordance with authorizations of management and directors of the company;
+and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
+acquisition, use, or disposition of the company’s assets that could have a material effect on the
+financial statements.
+Because of its inherent limitations, internal control over financial reporting may not prevent or
+detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
+subject to the risk that controls may become inadequate because of changes in conditions, or that
+the degree of compliance with the policies or procedures may deteriorate.
+In our opinion, management’s assessment that Callon Petroleum Company maintained effective internal
+control over financial reporting as of December 31, 2005, is fairly stated, in all material
+respects, based on criteria established in Internal
+Control—Integrated Framework issued by the Committee of Sponsoring
+Organizations of the Trading Commission. Also, in our opinion, Callon Petroleum Company maintained,
+in all material respects, effective internal control over financial reporting as of December 31,
+2005, based on the COSO criteria.
+72
+Table of Contents 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight
+Board (United States), the consolidated balance sheets of Callon Petroleum Company as of December
+31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity and
+cash flows for each of the three years in the period ended December 31, 2005 of Callon Petroleum
+Company and our report dated March 9, 2006, expressed an unqualified opinion thereon.
+/s/ Ernst & Young LLP 
+New Orleans, Louisiana 
+March 9, 2006
+73
+Table of Contents 
+ITEM 9.B OTHER INFORMATION 
+We have disclosed all information required to be disclosed in a current report on Form 8-K during
+the fourth quarter of the year ended December 31, 2005 in previously filed reports on Form 8-K.
+74
+Table of Contents 
+PART III. 
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. 
+For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 4, 2006 which will be filed with the
+Securities and Exchange Commission and is incorporated herein by reference.
+The Company has adopted a code of ethics that applies to the Company’s chief executive officer,
+chief financial officer and chief accounting officer. The full text of such code of ethics has
+been posted on the Company’s website at ww.callon.com, and is available free of charge in print to
+any shareholder who requests it. Request for copies should be addressed to the Secretary at 200
+North Canal Street, Natchez, Mississippi 39120.
+ITEM 11. EXECUTIVE COMPENSATION. 
+For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 4, 2006 which will be filed with the
+Securities and Exchange Commission and is incorporated herein by reference.
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
+STOCKHOLDER MATTERS. 
+For information concerning the security ownership of certain beneficial owners and management, see
+the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of
+Stockholders on May 4, 2006 which will be filed with the Securities and Exchange Commission and is
+incorporated herein by reference.
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 4, 2006 which will be filed with the
+Securities and Exchange Commission and is incorporated herein by reference.
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES. 
+For information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 4, 2006 which will be filed with the
+Securities and Exchange Commission and is incorporated herein by reference.
+75
+Table of Contents 
+PART IV. 
+ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 
+(a) 1. The following is an index to the financial statements and financial statement schedules
+that are filed as part of this Form 10-K on pages 42 through 70.
+Report of Independent Registered Public Accounting Firm
+Consolidated Balance Sheets as of the Years Ended December 31, 2005 and 2004
+Consolidated Statements of Operations for the Three Years in the Period Ended 
+December 31, 2005
+Consolidated Statements of Stockholders’ Equity for the Three Years in the Period Ended 
+December 31, 2005
+Consolidated Statements of Cash Flows for the Three Years in the Period Ended 
+December 31, 2005
+Notes to Consolidated Financial Statements
+(a) 2. Schedules other than those listed above are omitted because they are not required, not
+applicable or the required information is included in the financial statements or notes thereto.
+(a) 3. Exhibits:
+2. 
+Plan of acquisition, reorganization, arrangement, liquidation or succession* 
+3. 
+Articles of Incorporation and Bylaws 
+3.1 
+Certificate of Incorporation of the Company, as amended (incorporated by
+reference to Exhibit 3.1 of the Company’s Annual Report on Form 10-K for the year
+ended December 31, 2003, File No. 001-14039) 
+3.2 
+Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the
+Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg. No.
+33-82408) 
+3.3 
+Certificate of Amendment to Certificate of Incorporation of the Company
+(incorporated by reference to Exhibit 3.3 of the Company’s Annual Report on Form
+10-K for the year ended December 31, 2003, File No. 001-14039) 
+4. 
+Instruments defining the rights of security holders, including indentures 
+4.1 
+Specimen Common Stock Certificate (incorporated by reference from Exhibit
+4.1 of the Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg.
+No. 33-82408) 
+76
+Table of Contents 
+4.2 
+Rights Agreement between Callon Petroleum Company and American Stock Transfer
+& Trust Company, Rights Agent, dated March 30, 2000 (incorporated by reference from
+Exhibit 99.1 of the Company’s Registration Statement on Form 8-A, filed April 6, 2000,
+File No. 001-14039) 
+4.3 
+Warrant dated as of June 29, 2001 entitling Duke Capital Partners, LLC to purchase
+common stock from the Company. (incorporated by reference to Exhibit 4.11 of the
+Company’s Quarterly Report on Form 10-Q for the period ended June 30,
+2001, File No. 001-14039) 
+4.4 
+Form of Warrants dated December 8, 2003 and December 29, 2003 entitling lenders under
+the Company’s $185 million amended and restated senior unsecured credit agreement dated
+December 23, 2003 to purchase common stock from the Company (incorporated by reference
+to Exhibit 4.14 of the Company’s Annual Report on Form 10-K for the year ended
+December 31, 2003, File No. 001-14039) 
+4.5 
+Indenture for the Company’s 9.75% Senior Notes due 2010, dated March 15, 2004 between
+Callon Petroleum Company and American Stock Transfer and Trust Company (incorporated by
+reference to Exhibit 4.16 of the Company’s Quarterly Report on Form 10-Q for the period
+ended March 31, 2004, File No. 001-14039) 
+9. 
+Voting trust agreement 
+None. 
+10. 
+Material contracts 
+10.1 
+Registration Rights Agreement dated September 16, 1994 between the Company
+and NOCO Enterprises, L. P. (incorporated by reference from Exhibit 10.2 of the
+Company’s Registration Statement on Form 8-B filed October 3,
+1994) 
+10.2 
+Counterpart to Registration Rights Agreement by and between the Company,
+Ganger Rolf ASA and Bonheur ASA. (incorporated by reference from Exhibit 10.2
+of the Company’s Report on Form 10-K for the fiscal year ended December 31,
+2000, File No. 001-14039) 
+10.3 
+Registration Rights Agreement dated September 16, 1994 between the Company
+and Callon Stockholders (incorporated by reference from Exhibit 10.3 of the Company’s
+Registration Statement on Form 8-B filed October 3, 1994) 
+10.4 
+Callon Petroleum Company 1994 Stock Incentive Plan (incorporated by
+reference from Exhibit 10.5 of the Company’s Registration Statement on Form 8-B filed
+October 3, 1994 
+10.5 
+Callon Petroleum Company 1996 Stock Incentive Plan as amended on May 9, 2000
+(incorporated by reference from Appendix I of the Company’s Definitive
+Proxy Statement of Schedule 14A filed March 28, 2000) 
+77
+Table of Contents 
+10.6 
+Conveyance of Overriding Royalty Interest from the Company to Duke Capital
+Partners, LLC, dated June 29, 2001 (incorporated by reference to Exhibit 10.03 of the
+Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2001, File No.
+001-14039) 
+10.7 
+Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference to
+Exhibit 10.13 of the Company’s Annual Report on Form 10-K for the year ended December 31,
+2001, File No. 001-14039) 
+10.8 
+Change of Control Severance Compensation Agreement by and between Callon Petroleum
+Company and Fred L. Callon, dated January 1, 2002 (incorporated
+by reference to Exhibit 10.15 of the Company’s Annual Report on Form 10-K for the year ended December 31,
+2001, File No. 001-14039) 
+10.9 
+Medusa Spar Agreement dated as of August 8, 2003, among Callon Petroleum Operating
+Company, Murphy Exploration & Production Company-USA and Oceaneering
+International, Inc. (incorporated by reference to Exhibit 10.19 of the Company’s
+Annual Report on Form 10-K for the year ended December 31, 2003, File No.
+001-14039) 
+10.10 
+Credit Agreement dated as of December 18, 2003 among Medusa Spar LLC, The Bank of
+Nova Scotia, as Administrative Agent, Bank One, N.A., Sun Trust Bank, as
+Syndication Agents and other Lenders Party. (incorporated by reference to
+Exhibit 10.20 of the Company’s Annual Report on Form 10-K for
+the year ended December 31, 2003, File No. 001-14039) 
+10.11 
+Credit Agreement dated as of June 14, 2004 between the Company and Union Bank of
+California, N.A., as Administrative Agent (incorporated by reference to
+Exhibit 10.1 of the Company’s Current Report on Form 8-K dated June 14, 2004,
+File No. 001-14039) 
+10.12 
+Change of Control Severance Compensation Agreement by and between Callon Petroleum
+and John S. Weatherly dated January 1, 2002 (incorporated by reference to
+Exhibit 10.14 of the Company’s Annual Report on Form 10-K for the year ended
+December 31, 2001, File No. 001-14039) 
+11. 
+Statement re computation of per share earnings* 
+12. 
+Statements re computation of ratios* 
+13. 
+Annual Report to security holders, Form 10-Q or quarterly reports* 
+14. 
+Code of Ethics 
+14.1 
+Code of Ethics for Chief Executive Officers and Senior Financial Officers
+(incorporated by reference to Exhibit 14.1 of the Company’s Annual Report
+on Form 10-K for the year ended December 31, 2003, File No. 001-14039) 
+16. 
+Letter re change in certifying accountant* 
+78
+Table of Contents 
+18. 
+Letter re change in accounting principles* 
+21. 
+Subsidiaries of the Company 
+21.1 
+Subsidiaries of the Company (incorporated by reference from Exhibit 21.1 of
+the Company’s Registration Statement on Form 8-B filed October 3, 1994) 
+22. 
+Published report regarding matters submitted to vote of security holders* 
+23. 
+Consents of experts and counsel 
+23.1 
+Consent of Ernst & Young LLP 
+23.2 
+Consent of Huddleston & Co., Inc. 
+24. 
+Power of attorney* 
+31. 
+Rule 13a-14(a) Certifications 
+31.1 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) 
+32 
+Section 1350 Certifications 
+32.1 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(b) 
+99. 
+Additional Exhibits* 
+*Inapplicable to this filing.
+79
+Table of Contents 
+SIGNATURES 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed
+below by the following persons on behalf of the registrant and in the capacities and on the dates
+indicated.
+CALLON PETROLEUM COMPANY 
+Date: March 15, 2006
+/s/ Fred L. Callon
+Fred L. Callon (principal executive officer,
+principal financial officer and director) 
+Date:
+March 15, 2006
+/s/ Rodger W. Smith 
+Rodger W. Smith (principal accounting officer) 
+Date: March 15, 2006
+/s/ Richard Flury 
+Richard Flury (director) 
+Date: March 15, 2006
+/s/ John C. Wallace 
+John C. Wallace (director) 
+Date: March 15, 2006
+/s/ B. F. Weatherly 
+B. F. Weatherly (director) 
+Date: March 15, 2006
+/s/ Richard O. Wilson 
+Richard O. Wilson (director) 
+80
+Table of Contents 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
+registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
+duly authorized.
+CALLON PETROLEUM COMPANY 
+Date: March 15, 2006
+By:
+/s/ Fred L. Callon
+Fred L. Callon, President and
+Chief Executive Officer 
+81
\ No newline at end of file
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diff --git a/raw/filings/0000928022/2005/0000950134-06-005141/item1.txt b/raw/filings/0000928022/2005/0000950134-06-005141/item1.txt
new file mode 100644
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@@ -0,0 +1,5049 @@
+ITEM 1 and 2. BUSINESS and PROPERTIES 
+Overview 
+Callon Petroleum Company has been engaged in the exploration, development, acquisition and
+production of oil and gas properties since 1950. Our properties are geographically
+concentrated primarily offshore in the Gulf of Mexico and onshore in Louisiana and Alabama. We
+were incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of
+a publicly traded limited partnership, a joint venture with a consortium of European investors and
+an independent energy company owned by members of current management. As used herein, the
+“Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors
+and subsidiaries unless the context requires otherwise.
+In 1989, we began increasing our reserves through the acquisition of producing properties that were
+geologically complex, had (or were analogous to fields with) an established production history from
+stacked pay zones and were candidates for exploitation. We focused on reducing operating costs and
+implementing production enhancements through the application of technologically advanced production
+and recompletion techniques.
+Over the past 10 years, we have placed emphasis on the acquisition of acreage with exploration and
+development drilling opportunities in the Gulf of Mexico shelf and deepwater areas. At December
+31, 2005, we owned working interests in a total of 88 blocks/leases covering 152,000 net acres. To
+minimize risk we join with industry partners to explore federal offshore blocks acquired in the
+Gulf of Mexico. We perform extensive geological and geophysical studies using computer-aided
+exploration techniques (CAEX), including, where appropriate, the acquisition of 3-D seismic or
+high-resolution 2-D data to facilitate these efforts. We continue to develop prospects on the
+shelf through our 3-D seismic partnership using Amplitude versus Offset (“AVO”) technology. In
+1998, we began exploration in the Gulf of Mexico deepwater area (generally 900 to 5,500 feet of
+water) and during the fourth quarter of 2003, our first two deepwater projects, the Medusa and
+Habanero fields, began production. Please see “Significant Properties” for a more detailed
+discussion.
+We ended the year 2005 with estimated net proved reserves of 188.6 billion cubic feet of natural
+gas equivalent (“Bcfe”). This represents a decrease of 1% from 2004 year-end estimated net proved
+reserves of 191.1 Bcfe. We produced 18.8 million cubic feet of natural gas equivalent (“Mmcfe”)
+and had net reserve additions of 16.3 Mmcfe.
+The major focus of our future operations is expected to continue to be the exploration for and
+development of oil and gas properties, primarily in the Gulf of Mexico.
+Availability of Reports 
+All of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
+8-K, and amendments to such reports as well as other filings we make pursuant to Section 13(a) and
+15(d) of the Securities Exchange Act of 1934 are available free of charge on our Internet website.
+The address of our Internet website is www.callon.com. Our Securities and Exchange Commission
+(“SEC”) filings are available on our website as soon as they are posted to the EDGAR database on
+the SEC’s website.
+2
+Table of Contents 
+Business Strategy 
+Our goal is to increase shareholder value by increasing our reserves, production, cash flow and
+earnings. We seek to achieve these goals through the following strategies:
+• 
+focus on Gulf of Mexico exploration with a balance between shelf and deepwater areas
+using the latest available technology; 
+• 
+aggressively explore our existing prospect inventory; and 
+• 
+replenish our prospect inventory with increasing emphasis on prospect generation using
+AVO technology. 
+Exploration and Development Activities 
+In 2005, capital expenditures for exploration and development costs related to oil and gas
+properties totaled approximately $90 million, of which $17 million was included in accounts payable
+at December 31, 2005. We incurred approximately:
+• 
+$34 million in the Gulf of Mexico shelf and onshore south Louisiana areas which included
+the drilling of 11 exploratory wells, four of which were unsuccessful; 
+• 
+$16 million for completion and development costs associated with our successful drill
+wells, two of which came online in 2005 and the remaining are scheduled to come online in
+the first half of 2006; 
+• 
+$5 million in our deepwater area, which includes the development and completion costs
+for North Medusa; 
+• 
+$15 million for leasehold and seismic costs; 
+• 
+$7 million for the acquisition of producing oil and gas properties and miscellaneous costs; and 
+• 
+$6 million for capitalized interest and $7 million for capitalized general and
+administration costs allocable directly to exploration and development projects. 
+Risk Factors 
+A decrease in oil and gas prices may adversely affect our results of operations and financial
+condition . Our success is highly dependent on prices for oil and gas, which are extremely volatile.
+Any substantial or extended decline in the price of oil or gas would have a material adverse effect
+on us. Oil and gas markets are both seasonal and cyclical. The prices of oil and gas depend on
+factors we cannot control such as weather, economic conditions, and levels of production, actions
+by OPEC and other countries and government actions. Prices of oil and gas will affect the following
+aspects of our business:
+• 
+our revenues, cash flows and earnings; 
+• 
+the amount of oil and gas that we are economically able to produce; 
+• 
+our ability to attract capital to finance our operations and the cost of the capital; 
+• 
+the amount we are allowed to borrow under our senior secured credit facility; 
+• 
+the value of our oil and gas properties; and 
+• 
+the profit or loss we incur in exploring for and developing our reserves. 
+3
+Table of Contents 
+Our reserve information represents estimates that may turn out to be incorrect if the assumptions
+upon which these estimates are based are inaccurate. Any material inaccuracies in these reserve
+estimates or underlying assumptions will materially affect the quantities and present value of our
+reserves. The process of estimating oil and gas reserves is complex. It requires interpretations
+of available technical data and various assumptions, including assumptions relating to economic
+factors. Any significant inaccuracies in these interpretations or assumptions could materially
+affect the estimated quantities and present value of reserves shown in this annual report.
+In order to prepare these estimates, we must project production rates and the timing of development
+expenditures. The assumptions regarding the timing and costs to commence production from our
+deepwater wells used in preparing our reserves are often subject to revisions over time as
+described under “Our deepwater operations have special operational risks that may negatively affect
+the value of those assets.” We must also analyze available geological, geophysical, production and
+engineering data, the extent, quality and reliability of which can vary. The process also requires
+us to make economic assumptions, such as oil and gas prices, drilling and operating expenses,
+capital expenditures, taxes and availability of funds. Therefore, estimates of oil and gas
+reserves are inherently imprecise.
+Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating
+expenses and quantities of recoverable oil and gas reserves most likely will vary from the
+estimates. Any significant variance could materially affect the estimated quantities and present
+value of reserves shown in this report. In addition, estimates of proved reserves may be adjusted
+to reflect production history, results of exploration and development, prevailing oil and gas
+prices and other factors, many of which are beyond our control.
+Also, under MMS rules governing our deepwater Medusa property and several of our shallow water,
+deep natural gas properties and prospects, we are eligible for royalty suspensions depending on the
+difference between the average monthly New York Mercantile Exchange (NYMEX) sales price for oil or
+gas and price thresholds set by the MMS. As a result, our reserve estimates may increase or
+decrease depending upon the relation of price thresholds versus the average NYMEX prices.
+You should not assume that the present value of future net cash flows from our proved reserves
+referred to in this report is the current market value of our estimated oil and gas reserves. In
+accordance with SEC requirements, we generally base the estimated discounted future net cash flows
+from our proved reserves on prices and costs on the date of the estimate. Actual future prices and
+costs may differ materially from those used in the present value estimate.
+The discounted present value of our oil and gas reserves is prepared in accordance with guidelines
+established by the SEC. A purchaser of reserves would use numerous other factors to value the
+reserves. The discounted present value of reserves, therefore, does not necessarily represent the
+fair market value of those reserves.
+On December 31, 2005, approximately 58% of the discounted present value of our estimated net proved
+reserves were proved undeveloped. Proved undeveloped reserves represented 60% of total proved
+reserves. Most of these proved undeveloped reserves were attributable to our deepwater properties.
+Development of these properties is subject to additional risks as described above.
+4
+Table of Contents 
+Information about reserves constitutes forward-looking information. See “Forward-Looking
+Statements” for information regarding forward-looking information. 
+Unless we are able to replace reserves which we have produced, our cash flows and production will
+decrease over time. Our future success depends upon our ability to find, develop and acquire oil
+and gas reserves that are economically recoverable. As is generally the case for Gulf properties,
+our producing properties usually have high initial production rates, followed by a steep decline in
+production. As a result, we must continually locate and develop or acquire new oil and gas reserves
+to replace those being depleted by production. We must do this even during periods of low oil and
+gas prices when it is difficult to raise the capital necessary to finance these activities and
+during periods of high operating costs when it is expensive to contract for drilling rigs and other
+equipment and personnel necessary to explore for oil and gas. Without successful
+exploration or acquisition activities, our reserves, production and revenues will decline rapidly.
+We cannot assure you that we will be able to find and develop or acquire additional reserves at an
+acceptable cost.
+Also, because of the aggregate short life of our reserves, our return on the investment we make in
+our oil and gas wells and the value of our oil and gas wells will depend significantly on prices
+prevailing during relatively short production periods.
+A significant part of the value of our production and reserves is concentrated in a small number of
+offshore properties, and any production problems or inaccuracies in reserve estimates related to
+those properties would adversely impact our business. During 2005, 86% of our daily production
+came from five of our properties in the Gulf of Mexico. Moreover, one property accounted for 43% of
+our production during this period. In addition, at December 31, 2005, most of our proved reserves
+were located in three fields in the Gulf of Mexico, with approximately 76% of our total net proved
+reserves attributable to these properties. If mechanical problems, storms or other events
+curtailed a substantial portion of this production or if the actual reserves associated with any
+one of these producing properties are less than our estimated reserves, our results of operations
+and financial condition could be adversely affected.
+Our focus on exploration projects increases the risks inherent in our oil and gas activities. Our
+business strategy focuses on replacing reserves through exploration, where the risks are greater
+than in acquisitions and development drilling. Although we have been successful in exploration in
+the past, we cannot assure you that we will continue to increase reserves through exploration or at
+an acceptable cost. Additionally, we are often uncertain as to the future costs and timing of
+drilling, completing and producing wells. Our drilling operations may be curtailed, delayed or
+canceled as a result of a variety of factors, including:
+• 
+unexpected drilling conditions; 
+• 
+pressure or inequalities in formations; 
+• 
+equipment failures or accidents; 
+• 
+adverse weather conditions; 
+• 
+compliance with governmental requirements; and 
+• 
+shortages or delays in the availability of drilling rigs and the delivery of equipment. 
+5
+Table of Contents 
+We do not operate all of our properties and have limited influence over the operations of some of
+these properties, particularly our deepwater properties. Our lack of control could result in the
+following:
+• 
+the operator may initiate exploration or development at a faster or slower pace than we
+prefer; 
+• 
+the operator may propose to drill more wells or build more facilities on a project than
+we have funds for or that we deem appropriate, which may mean that we are unable to
+participate in the project or share in the revenues generated by the project even though we
+paid our share of exploration costs; and 
+• 
+if an operator refuses to initiate a project, we may be unable to pursue the project. 
+Any of these events could materially reduce the value of our non-operated properties.
+Our deepwater operations have special operational risks that may negatively affect the value of
+those assets. Drilling operations in the deepwater area are by their nature more difficult and
+costly than drilling operations in shallow water. Deepwater drilling operations require the
+application of more advanced drilling technologies involving a higher risk of technological failure
+and usually have significantly higher drilling costs than shallow water drilling operations.
+Deepwater wells are completed using sub-sea completion techniques that require substantial time and
+the use of advanced remote installation equipment. These operations involve a high risk of
+mechanical difficulties and equipment failures that could result in significant cost overruns.
+In deepwater, the time required to commence production following a discovery is much longer than in
+shallow water and on-shore. Deepwater discoveries require the construction of expensive production
+facilities and pipelines prior to production. We cannot estimate the costs and timing of the
+construction of these facilities with certainty, and the accuracy of our estimates will be affected
+by a number of factors beyond our control, including the following:
+• 
+decisions made by the operators of our deepwater wells; 
+• 
+the availability of materials necessary to construct the facilities; 
+• 
+the proximity of our discoveries to pipelines; and 
+• 
+the price of oil and natural gas. 
+Delays and cost overruns in the commencement of production will affect the value of our deepwater
+prospects and the discounted present value of reserves attributable to those prospects.
+Competitive industry conditions may negatively affect our ability to conduct operations. We
+operate in the highly competitive areas of oil and gas exploration, development and production. We
+compete for the purchase of leases in the Gulf of Mexico from the U. S. government and from other
+oil and gas companies. These leases include exploration prospects as well as properties with
+proved reserves. Factors that affect our ability to compete in the marketplace include:
+6
+Table of Contents 
+• 
+our access to the capital necessary to drill wells and acquire properties; 
+• 
+our ability to acquire and analyze seismic, geological and other information relating to
+a property; 
+• 
+our ability to retain the personnel necessary to properly evaluate seismic and other
+information relating to a property; 
+• 
+the location of, and our ability to access, platforms, pipelines and other facilities
+used to produce and transport oil and gas production; 
+• 
+the standards we establish for the minimum projected return on an investment of our
+capital; and 
+• 
+the availability of alternate fuel sources. 
+Our competitors include major integrated oil companies, substantial independent energy companies,
+and affiliates of major interstate and intrastate pipelines and national and local gas gatherers,
+many of which possess greater financial, technological and other resources than we do.
+Our competitors may use superior technology, which we may be unable to afford or which would
+require costly investment by us in order to compete. Our industry is subject to rapid and
+significant advancements in technology, including the introduction of new products and services
+using new technologies. As our competitors use or develop new technologies, we may be placed at a
+competitive disadvantage, and competitive pressures may force us to implement new technologies at a
+substantial cost. In addition, our competitors may have greater financial, technical and personnel
+resources that allow them to enjoy technological advantages and may in the future allow them to
+implement new technologies before we can. We cannot be certain that we will be able to implement
+technologies on a timely basis or at a cost that is acceptable to us. One or more of the
+technologies that we currently use or that we may implement in the future may become obsolete, and
+we may be adversely affected. For example, marine seismic acquisition technology has been
+characterized by rapid technological advancements in recent years, and further significant
+technological developments could substantially impair our 3-D seismic data’s value.
+We may not be able to replace our reserves or generate cash flows if we are unable to raise
+capital. We will be required to make substantial capital expenditures to develop our existing
+reserves, and to discover new oil and gas reserves. Historically, we have financed these
+expenditures primarily with cash from operations, proceeds from bank borrowings and proceeds from
+the sale of debt and equity securities. See “Management’s Discussion and Analysis of Financial
+Condition and Results of Operations — Liquidity and Capital Resources” for a discussion of
+our capital budget. We cannot assure you that we will be able to raise capital in the future. We
+also make offers to acquire oil and gas properties in the ordinary course of our business. If these
+offers are accepted, our capital needs may increase substantially.
+We expect to continue using our senior secured credit facility to borrow funds to supplement our
+available cash. The amount we may borrow under our senior secured credit facility may not exceed a
+borrowing base determined by the lenders under such facility based on their projections of our
+future production, production costs, taxes, commodity prices and any other factors deemed relevant
+by our lenders. We cannot control the assumptions the lenders use to calculate our borrowing base.
+The lenders may, without our consent, adjust the borrowing base semiannually or in situations where
+we purchase or sell assets or issue debt securities. If our borrowings under the senior secured
+credit facility exceed the borrowing base, the lenders may require that we repay the excess. If
+this were to occur, we might have to sell assets or seek financing from other sources. Sales of
+assets could further reduce the amount of our borrowing base. We cannot assure you that we would be
+successful in selling assets or arranging substitute financing. If we were not able to repay
+borrowings under our senior secured credit facility to reduce the outstanding amount to less than
+the borrowing base, we would be in default under our senior secured credit facility. For a
+description of our senior secured credit facility and its principal terms and conditions, see
+7
+Table of Contents 
+“Management’s Discussion and Analysis of Financial Condition and Results of Operations
+— Liquidity and Capital Resources” and Note 5 to our Consolidated Financial Statements.
+Our decision to drill a prospect is subject to a number of factors and we may decide to alter our
+drilling schedule or not drill at all. A prospect is a property on which we have identified what
+our geoscientists believe, based on available seismic and geological information, to be indications
+of hydrocarbons. Our prospects are in various stages of evaluation, ranging from a prospect which
+is ready to drill to a prospect which will require substantial additional seismic data processing
+and interpretation. Whether we ultimately drill a prospect may depend on the following factors:
+• 
+receipt of additional seismic data or the reprocessing of existing data; 
+• 
+material changes in oil or gas prices; 
+• 
+the costs and availability of drilling rigs; 
+• 
+the success or failure of wells drilled in similar formations or which would use the
+same production facilities; 
+• 
+availability and cost of capital; 
+• 
+changes in the estimates of the costs to drill or complete wells; 
+• 
+our ability to attract other industry partners to acquire a portion of the working
+interest to reduce exposure to costs and drilling risks; and 
+• 
+decisions of our joint working interest owners. 
+We will continue to gather data about our prospects and it is possible that additional information
+may cause us to alter our drilling schedule or determine that a prospect should not be pursued at
+all. You should understand that our plans regarding our prospects are subject to change.
+Weather, unexpected subsurface conditions, and other unforeseen operating hazards may adversely
+impact our ability to conduct business. There are many operating hazards in exploring for and
+producing oil and gas, including:
+• 
+our drilling operations may encounter unexpected formations or pressures, which could
+cause damage to equipment or personal injury; 
+• 
+we may experience equipment failures which curtail or stop production; 
+• 
+we could experience blowouts or other damages to the productive formations that may
+require a well to be re-drilled or other corrective action to be taken; and 
+• 
+because of these or other events, we could experience environmental hazards, including
+oil spills, gas leaks, and ruptures. 
+In the event of any of the foregoing, we may be subject to interrupted production or substantial
+environmental liability due to injury to or loss of life, damage to or destruction of property,
+natural resources and equipment, pollution and other environmental damage, investigation and
+remediation requirements. Moreover, a substantial portion of our operations are offshore and are
+subject to a variety of risks peculiar to the marine environment such as capsizing, collisions,
+hurricanes and other adverse weather conditions. These conditions can cause substantial damage to
+facilities and interrupt production. Offshore operations are also subject to more extensive
+governmental regulation.
+We cannot assure you that we will be able to maintain adequate insurance at rates we consider
+reasonable to cover our possible losses from operating hazards. The occurrence of a significant
+event not fully insured or indemnified against could materially and adversely affect our financial
+condition and results of operations.
+8
+Table of Contents 
+We may not have production to offset hedges; by hedging, we may not benefit from price increases. 
+Part of our business strategy is to reduce our exposure to the volatility of oil and gas prices by
+hedging a portion of our production. In a typical hedge transaction, we will have the right to
+receive from the other parties to the hedge the excess of the fixed price specified in the hedge
+over a floating price based on a market index, multiplied by the quantity hedged. If the floating
+price exceeds the fixed price, we are required to pay the other parties this difference multiplied
+by the quantity hedged. We are required to pay the difference between the floating price and the
+fixed price when the floating price exceeds the fixed price regardless of whether we have
+sufficient production to cover the quantities specified in the hedge. Significant reductions in
+production at times when the floating price exceeds the fixed price could require us to make
+payments under the hedge agreements even though such payments are not offset by sales of
+production. Hedging will also prevent us from receiving the full advantage of increases in oil or
+gas prices above the fixed amount specified in the hedge. We also enter into price “collars” to
+reduce the risk of changes in oil and gas prices. Under a collar, no payments are due by either
+party so long as the market price is above a floor set in the collar and below a ceiling. If the
+price falls below the floor, the counter-party to the collar pays the difference to us and if the
+price is above the ceiling, we pay the counter-party the difference. Another type of hedging
+contract we have entered into is a put contract. Under a put, if the price falls below the set
+floor price, the counter-party to the contract pays the difference to us. See “Quantitative and
+Qualitative Disclosures About Market Risks” for a discussion of our hedging practices.
+Compliance with environmental and other government regulations could be costly and could negatively
+impact production. Our operations are subject to numerous laws and regulations governing the
+operation and maintenance of our facilities and the discharge of materials into the environment or
+otherwise relating to environmental protection. For a discussion of the material regulations
+applicable to us, see “Regulations”. These laws and regulations may:
+• 
+require that we acquire permits before commencing drilling; 
+• 
+restrict the substances that can be released into the environment in connection with
+drilling and production activities; 
+• 
+limit or prohibit drilling activities on protected areas such as wetlands or wilderness
+areas; and 
+• 
+require remedial measures to mitigate pollution from former operations, such as
+dismantling abandoned production facilities. 
+Under these laws and regulations, we could be liable for personal injury and clean-up costs and
+other environmental and property damages, as well as administrative, civil and criminal penalties.
+We maintain limited insurance coverage for sudden and accidental environmental damages. We do not
+believe that insurance coverage for environmental damages that occur over time is available at a
+reasonable cost. Also, we do not believe that insurance coverage for the full potential liability
+that could be caused by sudden and accidental environmental damages is available at a reasonable
+cost. Accordingly, we may be subject to liability or we may be required to cease production from
+properties in the event of environmental damages.
+9
+Table of Contents 
+Factors beyond our control affect our ability to market production and our financial results. The
+ability to market oil and gas from our wells depends upon numerous factors beyond our control.
+These factors include:
+• 
+the extent of domestic production and imports of oil and gas; 
+• 
+the proximity of the gas production to gas pipelines; 
+• 
+the availability of pipeline capacity; 
+• 
+the demand for oil and gas by utilities and other end users; 
+• 
+the availability of alternative fuel sources; 
+• 
+the effects of inclement weather; 
+• 
+state and federal regulation of oil and gas marketing; and 
+• 
+federal regulation of gas sold or transported in interstate commerce. 
+Because of these factors, we may be unable to market all of the oil or gas we produce. In addition,
+we may be unable to obtain favorable prices for the oil and gas we produce.
+If oil and gas prices decrease, we may be required to take writedowns of the carrying value of our
+oil and gas properties. We may be required to writedown the carrying value of our oil and gas
+properties when oil and gas prices are low or if we have substantial downward adjustments to our
+estimated net proved reserves, increases in our estimates of development costs or deterioration in
+our exploration results. Under the full-cost method which we use to account for our oil and gas
+properties, the net capitalized costs of our oil and gas properties may not exceed the present
+value, discounted at 10%, of future net cash flows from estimated net proved reserves, using period
+end oil and gas prices or prices as of the date of our auditor’s report, plus the lower of cost or
+fair market value of our unproved properties. If net capitalized costs of our oil and gas
+properties exceed this limit, we must charge the amount of the excess to earnings. This type of
+charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity.
+We review the carrying value of our properties quarterly, based on prices in effect as of the end
+of each quarter or at the time of reporting our results. Once incurred, a writedown of oil and gas
+properties is not reversible at a later date, even if prices increase.
+There are inherent limitations in all control systems, and misstatements due to error or fraud that
+could seriously harm our business may occur and not be detected. Our management, including our
+Chief Executive and Financial Officer, does not expect that our internal controls and disclosure
+controls will prevent all possible error and all fraud. A control system, no matter how well
+conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of
+the control system are met. In addition, the design of a control system must reflect the fact that
+there are resource constraints and the benefit of controls must be relative to their costs.
+Because of the inherent limitations in all control systems, an evaluation of controls can only
+provide reasonable assurance that all material control issues and instances of fraud, if any, in
+our company have been detected. These inherent limitations include the realities that judgments in
+decision-making can be faulty and that breakdowns can occur because of simple error or mistake.
+Further, controls can be circumvented by the individual acts of some persons or by collusion of two
+or more persons. The design of any system of controls is based in part upon certain assumptions
+about the likelihood of future events, and there can be no assurance that any design will succeed
+in achieving its stated goals under all potential future conditions. Because of inherent
+limitations in a cost-effective control system, misstatements due to error or fraud may occur and
+not be detected. A failure of our controls and procedures to detect error or fraud could seriously
+harm our business and results of operations.
+10
+Table of Contents 
+Forward-Looking Statements 
+In this report, we have made many forward-looking statements. We cannot assure you that the plans,
+intentions or expectations upon which our forward-looking statements are based will occur. Our
+forward-looking statements are subject to risks, uncertainties and assumptions, including those
+discussed elsewhere in this report. Forward-looking statements include statements regarding:
+• 
+our oil and gas reserve quantities, and the discounted present value of these
+reserves; 
+• 
+the amount and nature of our capital expenditures; 
+• 
+drilling of wells; 
+• 
+the timing and amount of future production and operating costs; 
+• 
+business strategies and plans of management; and 
+• 
+prospect development and property acquisitions. 
+Some of the risks, which could affect our future results and could cause results to differ
+materially from those expressed in our forward-looking statements, include:
+• 
+general economic conditions; 
+• 
+the volatility of oil and natural gas prices; 
+• 
+the uncertainty of estimates of oil and natural gas reserves; 
+• 
+the impact of competition; 
+• 
+the availability and cost of seismic, drilling and other equipment; 
+• 
+operating hazards inherent in the exploration for and production of oil and natural
+gas; 
+• 
+difficulties encountered during the exploration for and production of oil and
+natural gas; 
+• 
+difficulties encountered in delivering oil and natural gas to commercial markets; 
+• 
+changes in customer demand and producers’ supply; 
+• 
+the uncertainty of our ability to attract capital; 
+• 
+compliance with, or the effect of changes in, the extensive governmental
+regulations regarding the oil and natural gas business; 
+• 
+actions of operators of our oil and gas properties; and 
+• 
+weather conditions. 
+The information contained in this report, including the information set forth under the heading
+“Risk Factors,” identifies additional factors that could affect our operating results and
+performance. We urge you to carefully consider these factors and the other cautionary statements in
+this report. Our forward-looking statements speak only as of the date made, and we have no
+obligation to update these forward-looking statements.
+Corporate Offices 
+Our headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned
+space. We also maintain a business office in Houston, Texas, and own or lease field offices in the
+area of the major fields in which we operate properties or have a significant interest. Replacement
+of any of our leased offices would not result in material expenditures by us as alternative
+locations to our leased space are anticipated to be readily available . 
+11
+Table of Contents 
+Employees 
+We had 87 employees as of December 31, 2005, none of whom are currently represented by a union. We
+believe that we have good relations with our employees. We employ five petroleum engineers and
+seven petroleum geoscientists.
+Regulations 
+General . The oil and gas industry is subject to regulation at the federal, state and local level,
+and some of the laws, rules and regulations that govern our operations carry substantial penalties
+for non-compliance. This regulatory burden increases our cost of doing business and, consequently,
+affects our profitability.
+Exploration and Production. Our operations are subject to federal, state and local regulations
+that include requirements for permits to drill and to conduct other operations and for provision of
+financial assurances (such as bonds) covering drilling and well operations. Other activities
+subject to regulation are:
+• 
+the location of wells, 
+• 
+the method of drilling and completing wells, 
+• 
+the rate of production, 
+• 
+the surface use and restoration of properties upon which wells are drilled, 
+• 
+the plugging and abandoning of wells, 
+• 
+the disposal of fluids used or other wastes obtained in connection with operations, 
+• 
+the marketing, transportation and reporting of production, and 
+• 
+the valuation and payment of royalties. 
+For instance, our OCS leases in federal waters are administered by the Minerals Management Service,
+or MMS, and require compliance with detailed MMS regulations and orders. Lessees must obtain MMS
+approval for exploration plans and exploitation and production plans prior to the commencement of
+such operations. The MMS has promulgated regulations requiring offshore production facilities
+located on the OCS to meet stringent engineering and construction specifications. The MMS also has
+regulations restricting the flaring or venting of natural gas, and prohibiting the flaring of
+liquid hydrocarbons and oil without prior authorization. MMS policies concerning the volume of
+production that a lessee must have to maintain an offshore lease beyond its primary term also are
+applicable to Callon. Similarly, the MMS has promulgated other regulations governing the plugging
+and abandonment of wells located offshore and the installation and removal of all production
+facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires
+that lessees have substantial net worth or post bonds or other acceptable assurances that such
+obligations will be met. The cost of these bonds or other surety can be substantial, and there is
+no assurance that bonds or other surety can be obtained in all cases. Under some circumstances,
+the MMS may require any of our operations on federal leases to be suspended or terminated. Any
+such suspension or termination could materially adversely affect our financial conditions and
+results of operations.
+Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline
+transportation. The price and terms for access to pipeline transportation remain subject to
+extensive federal regulation. If these regulations change, we could face higher transmission costs
+for our production and, possibly, reduced access to transmission capacity.
+12
+Table of Contents 
+We do not currently anticipate that compliance with existing laws and regulations governing
+exploration and production will have a significantly adverse effect upon our capital expenditures,
+earnings or competitive position.
+Various proposals and proceedings that might affect the petroleum industry are pending before
+Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the
+courts. The industry historically has been heavily regulated and we can offer you no assurance
+that the less stringent regulatory approach recently pursued by the FERC and Congress will continue
+nor can we predict what effect such proposals or proceedings may have on our operations.
+Environmental Regulation. Various federal, state and local laws and regulations concerning the
+discharge of contaminants into the environment, the generation, storage, transportation and
+disposal of contaminants, and the protection of public health, natural resources, wildlife and the
+environment affect our exploration, development and production operations, including processing
+facilities. We must take into account the cost of complying with environmental regulations in
+planning, designing, drilling, constructing, operating and abandoning wells. In most instances, the
+regulatory requirements relate to the handling and disposal of drilling and production waste
+products, water and air pollution control procedures, and the remediation of petroleum-product
+contamination. In addition, our operations may require us to obtain permits for, among other
+things,
+• 
+air emissions, 
+• 
+discharges into surface waters, and 
+• 
+the construction and operations of underground injection wells or surface pits to
+dispose of produced saltwater and other nonhazardous oilfield wastes. 
+In the event of an unauthorized discharge, emission or activity, we may be liable for penalties,
+costs and damages. Under state and federal laws, we could be required to remove or remediate
+previously disposed wastes and remediate contamination, including contamination in surface water,
+soil or groundwater, caused by disposal of that waste. We could be responsible for wastes disposed
+of or released by us or prior owners or operators at properties owned or leased by us or at
+locations where wastes have been taken for disposal. We could also be required to suspend or cease
+operations in contaminated areas, or to perform remedial well plugging operations or cleanups to
+prevent future contamination. The Environmental Protection Agency and various state agencies have
+limited the disposal options for hazardous and nonhazardous wastes. The owner and operator of a
+site, and persons that treated, disposed of or arranged for the disposal of hazardous substances
+found at a site, may be liable, without regard to fault or the legality of the original conduct,
+for the release of a hazardous substance into the environment. The Environmental Protection Agency,
+state environmental agencies and, in some cases, third parties are authorized to take actions in
+response to threats to human health or the environment and to seek to recover from responsible
+classes of persons the costs of such action. Furthermore, certain wastes generated by our oil and
+natural gas operations that are currently exempt from treatment as hazardous wastes may in the
+future be designated as hazardous wastes and, therefore, be subject to considerably more rigorous
+and costly operating and disposal requirements.
+Federal and state occupational safety and health laws require us to organize information about
+hazardous materials used, released or produced in our operations. Certain portions of this
+information must be provided to employees, state and local governmental authorities and local
+citizens. We are also subject to the requirements and reporting set forth in federal workplace
+standards.
+We have made and will continue to make expenditures to comply with environmental regulations and
+requirements. These are necessary business costs in the oil and gas industry. Although we are not
+fully
+13
+Table of Contents 
+insured against all environmental risks, we maintain insurance coverage which we believe is
+customary in the industry. Moreover, it is possible that other developments, such as stricter and
+more comprehensive environmental laws and regulations, as well as claims for damages to property or
+persons resulting from company operations, could result in substantial costs and liabilities,
+including civil and criminal penalties, to Callon. We believe we are in compliance with existing
+environmental regulations, and that, absent the occurrence of an extraordinary event the effect of
+which cannot be predicted, any noncompliance will not have a material adverse effect on our
+operations or earnings.
+Commitments and Contingencies 
+The Company’s activities are subject to federal, state and local laws and regulations governing
+environmental quality and pollution control. Although no assurances can be made, the Company
+believes that, absent the occurrence of an extraordinary event, compliance with existing federal,
+state and local laws, rules and regulating the release of materials in the environment or otherwise
+relating to the protection of the environment will not have a material effect upon the capital
+expenditures, earnings or the competitive position of the Company with respect to its existing
+assets and operations. The Company cannot predict what effect additional regulation or
+legislation, enforcement polices thereunder, and claims for damages to property, employees, other
+person, and the environment resulting from the Company’s operations could have on its activities.
+Property Summary 
+We are engaged in the exploration, development, acquisition and production of oil and gas
+properties. Our properties are concentrated offshore in the Gulf of Mexico and onshore, primarily,
+in Louisiana and Alabama. We have historically increased our reserves and production by focusing
+primarily on low to moderate risk exploration and acquisition opportunities in the Gulf of Mexico
+shelf area. In 1998, we expanded our area of exploration to include the Gulf of Mexico deepwater
+area. As of December 31, 2005, our estimated net proved reserves totaled 188.6 Bcfe and included
+18.4 million barrels of oil (“MMBbl”) and 78.0 billion cubic feet of natural gas (“Bcf”), with a
+pre-tax present value, discounted at 10%, of the estimated future net revenues based on constant
+prices in effect at year-end of $1.1 billion. Oil constitutes approximately 59% on an equivalent
+basis of our total estimated proved reserves and approximately 40% of our total estimated proved
+reserves are proved developed reserves.
+Our Medusa (Mississippi Canyon Blocks 538/582) and Habanero (Garden Banks Block 341) discoveries
+began production in the fourth quarter of 2003. A detailed discussion of each of these properties
+is provided in the “Significant Properties” section of this report. These two deepwater discoveries
+were responsible for 62% of our total production during 2005.
+14
+Table of Contents 
+Significant Properties 
+The following table shows discounted cash flows and estimated net proved oil and gas reserves by
+major field and for all other properties combined at December 31, 2005.
+Pre-tax 
+Estimated Net Proved Reserves 
+Discounted 
+Oil 
+Gas 
+Total 
+Present Value 
+Operator 
+(MBbls) 
+(MMcf) 
+(MMcfe) 
+($000) 
+(a)(b) 
+Gulf of Mexico Deepwater: 
+Garden Banks Block
+738/782/826/827
+“Entrada” 
+BP 
+7,772 
+29,126 
+75,760 
+$ 
+409,904 
+Mississippi Canyon 538/582
+“Medusa” 
+Murphy 
+6,566 
+4,814 
+44,208 
+255,386 
+Garden Banks Block 341
+“Habanero” 
+Shell 
+2,886 
+6,730 
+24,047 
+150,678 
+Gulf of Mexico Shelf: 
+West Cameron Block 295 
+HydroGOM/Cimarex 
+— 
+8,217 
+8,217 
+58,401 
+High Island Block A-540 
+Walter 
+106 
+3,305 
+3,939 
+24,127 
+Mobile Blocks 953/955 
+Callon 
+— 
+4,216 
+4,216 
+24,201 
+Mobile Block 864 Unit 
+Callon 
+— 
+3,517 
+3,517 
+19,008 
+North Padre Island Block 913 
+Callon 
+2 
+3,457 
+3,467 
+29,381 
+East Cameron Block 90 
+Callon 
+— 
+2,255 
+2,256 
+19,487 
+High Island Block 119 
+Kerr-McGee 
+25 
+1,822 
+1,970 
+14,803 
+Other 
+Various 
+70 
+4,107 
+4,530 
+19,319 
+Onshore and Other: 
+Alabama 
+Various 
+513 
+1,288 
+4,365 
+18,121 
+Louisiana 
+Various 
+356 
+4,714 
+6,848 
+38,335 
+Other States 
+Various 
+132 
+453 
+1,248 
+7,566 
+Total Net Proved Reserves 
+18,428 
+78,021 
+188,588 
+$ 
+1,088,714 
+(a) 
+Represents the present value of future net cash flows before deduction of federal income
+taxes, discounted at 10%, attributable to estimated net proved reserves as of December 31,
+2005, as set forth in the Company’s reserve reports prepared by its independent petroleum
+reserve engineers, Huddleston & Co., Inc. of Houston, Texas. 
+(b) 
+Includes a reduction for estimated plugging and abandonment costs that is reflected as a
+liability on our balance sheet at December 31, 2005, in accordance with Statement of Financial
+Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). See
+the Oil and Gas Reserve table for the standardized measure of discounted future net cash flow
+which is a required calculation by the SEC. 
+15
+Table of Contents 
+Gulf of Mexico Deepwater 
+Entrada, Garden Banks Blocks 738/782/826/827 
+The Entrada discovery is located in approximately 4,500 feet of water in the Gulf of Mexico. Two
+wells and seven sidetracks have been drilled to date. The Entrada Area is characterized by a
+northwest plunging salt ridge with multiple stacked amplitudes trapped against the salt and various
+faults. We own a 20% working interest in this discovery with BP, the operator, holding the
+remaining working interest.
+An integrated project team consisting of personnel from BP and Callon, along with Conoco-Phillips
+and Devon Energy Corporation, the owners of production facilities in
+nearby Garden Banks 783, are working on a front-end engineering design study to tie-back
+Entrada to the production facilities. Project sanction is targeted for the
+second half of 2006 with first production expected in 2008.
+Medusa, Mississippi Canyon Blocks 538/582 
+Our Medusa deepwater discovery was announced in September 1999, after we drilled the initial test
+well in 2,235 feet of water to a total depth of 16,241 feet and encountered over 120 feet of pay in
+two intervals. Subsequent sidetrack drilling from the wellbore was used to determine the extent of
+the discovery and a second well was drilled in the first quarter of 2000 to further delineate the
+extent of the pay intervals. We own a 15% working interest, Murphy Exploration & Production Company
+(“Murphy”), the operator, owns a 60% working interest and ENI Deepwater, LLC, owns the remaining
+25% working interest.
+In 2001 a drilling program began which included four development wells and one sidetrack. The
+program included production casing being set on six wells to provide initial production take-points
+and was completed in the first half of 2002. The construction of a floating production system,
+spar, at Medusa was completed during the second quarter of 2003. The A-1 well was completed and
+tied into the spar and commenced production in late November 2003. The remaining five wells were
+completed and commenced production in 2004. Mississippi Canyon 538 #4, North Medusa, was drilled
+in 2003 and was temporarily abandoned after encountering 28 feet of net pay. The well bore was
+re-entered in the fourth quarter of 2004, sidetracked and reached an objective depth of 9,600 feet
+in January 2005. The sidetrack encountered 46 feet of net pay, was completed and commenced initial
+production in April 2005 at a gross rate of 5,000 barrels of oil equivalent per day.
+During 2005 the field produced 8.1 Bcfe net to us which accounted for 43% of our total production.
+Due to hurricanes and tropical storms during 2005, Medusa was not productive for approximately 102
+days. After repairs of damage to Medusa’s facilities and third-party transmission lines and
+production facilities caused by Hurricane Katrina, production was restored in November 2005 and
+pre-hurricane rates were achieved during December 2005. Medusa produced at an average daily gross
+rate of 34,000 barrels of crude oil and 35 MMcf during January 2006.
+In December 2003, we transferred our undivided 15% working interest in the spar production
+facilities to Medusa Spar LLC in exchange for cash proceeds of approximately $25 million and a 10%
+ownership interest in the LLC. A detailed discussion of this transaction is included in
+Management’s Discussion and Analysis of Financial Condition and Results of Operations-“Off-Balance
+Sheet Arrangements”.
+Habanero, Garden Banks Block 341 
+During February 1999, the initial test well on our Habanero deepwater discovery encountered over
+200 feet of net pay in two zones. Located in 2,000 feet of water, the well was drilled to a
+measured depth of
+16
+Table of Contents 
+21,158 feet. We own an 11.25% working interest in the well. The well is operated
+by Shell Deepwater Development Inc., which owns a 55% working interest, with the remaining working
+interest being owned by Murphy.
+A field delineation program began in mid-year 2001, which included three sidetracks of the
+discovery well. Production casing was set on this well through one of the sidetracks to the
+Habanero 52 oil and gas sand and the Habanero 55 gas sand. Also, a development well was drilled in
+the summer of 2003 which provides a take-point for production from the Habanero 52 oil sand. By
+means of a sub-sea completion and tie back to an existing production facility in the area operated
+by Shell, production from the Habanero 52 oil sand commenced in late November 2003 and from the
+Habanero 55 gas sand in January 2004. In July 2004 the #2 well producing the Habanero 52 oil sand
+developed mechanical difficulties with a subsurface control value and was shut-in resulting in a
+significant loss of production. Repairs were completed and production was restored in late
+December 2004. In addition, the #1 well producing the Habanero 55 gas sand was recompleted to the
+Habanero 55 oil sand in December 2004.
+During 2005 Habanero produced 3.5 Bcfe net to us which accounted for 19% of our total production.
+Due to hurricanes and tropical storms during 2005 the field was not productive for approximately 85
+days. After repairs of damage primarily to third-party transmission lines and production facilities
+caused by Hurricane Rita, production was restored in November 2005 and pre-hurricane rates were
+achieved during December 2005. Habanero produced at an average daily gross rate of 12,000 barrels
+of crude oil and 17 MMcf during January 2006.
+Gulf of Mexico Shelf 
+West Cameron Block 295 
+During the third quarter of 2005, the #2 well reached a total depth of 15,775 feet and logged 150
+feet of net pay in two zones. Each zone was encountered at the predicted depth and exceeded
+anticipated thickness. First production from the #2 well is expected in the first half of March
+2006 at a gross rate of approximately 30 MMcf per day. Callon holds a 20.5% working interest in
+the block and Hydro Gulf of Mexico, LLC is the operator.
+A second prospect on this block was also drilled during 2005. The #3 well was drilled to a depth
+of 16,286 feet in December 2005 and logged 110 feet of net (94 feet true vertical depth) pay in two
+zones. Production is expected to commence during May 2006 at a gross rate of approximately 10 MMcf
+per day. Callon holds a 20.5% working interest in the block and Cimarex Energy Company is the
+operator.
+High Island Block A-540 
+The #1 well was spud in November 2005 and reached a total depth of 9,450 feet the following month
+after logging 32 feet of net pay in the objective section. First production is scheduled to
+commence in July 2006 at an anticipated gross rate of approximately 11 MMcfe per day. The company
+owns a 60% working interest and Walter Oil and Gas is the operator.
+Mobile Blocks 953/955 
+We own a 100% working interest in these two blocks and we are the operator. In the fourth quarter
+of 2001, we initiated a production acceleration program for Mobile Blocks 952, 953 and 955, which
+were being produced through the Mobile Block 864 Unit facilities and were production constrained.
+An
+17
+Table of Contents 
+acceleration well was successfully drilled in the fourth quarter of 2001 and stand-alone
+production facilities were installed and production flow lines were rerouted to the new facilities.
+Production commenced through the new facilities in April 2002. In order to completely produce the
+proved reserves of the field we drilled a development well on Mobile Block 955 during the first
+quarter of 2004.
+During 2005 the three wells on the blocks produced 2.5 Bcf of natural gas net to us which accounted
+for 13.2% of our total production. Due to hurricanes and tropical storms during 2005, two of the
+wells were not productive for approximately 48 days and one well was down for 136 days. After
+repairs of damages caused by Hurricane Katrina, the field produced at an average daily gross rate
+of 7 MMcf during January 2006.
+Mobile Block 864 Unit 
+We operate the Mobile Block 864 Unit, in which we have a 66.4% working interest. The Unit has four
+producing wells, unit production facilities and covers portions of three blocks.
+During 2005 the Unit produced 833 MMcf of natural gas net to us which accounted for 4.4% of our
+total production. Due to hurricanes and tropical storms during 2005, the Unit was not productive
+for approximately 48 days. After repairs of damages caused by Hurricane Katrina, production was
+restored in November 2005. The field produced at an average daily gross rate of 4 MMcf during
+January 2006.
+North Padre Island Block 913 
+An exploratory well was drilled to a vertical depth of 8,082 feet in the fourth quarter of 2004 and
+found natural gas pay in multiple intervals. Currently, the well is being tied back to existing
+infrastructure on a nearby block. We are the operator and own a 50% working interest. First
+production is expected to commence in March 2006 at a gross rate of 15 MMcfe per day. The initial
+production was delayed due to equipment availability problems caused by Hurricanes Katrina and
+Rita.
+East Cameron Block 90 
+The #1 well reached total depth of 8,500 feet in January 2005 and encountered 42 feet of net pay at
+two intervals, including 34 feet in the primary objective. The well commenced initial production
+in December 2005 at a gross rate of 5 MMcf per day. Callon operates and owns a 61.7% working
+interest. The initial production was delayed due to equipment availability problems caused by
+Hurricanes Katrina and Rita.
+High Island Block 119 
+An initial exploratory well and one development well were drilled and completed in 2004. First
+production began in the third quarter of 2004. An exploratory well in an offsetting fault block
+was spud late in the fourth quarter of 2004 and was completed in 2005. We own a 22% working
+interest and Kerr- McGee Oil and Gas Corporation is the operator.
+These three wells produced 1.2 Bcfe of natural gas net to our interest during 2005 which accounted
+for 6.5% of our total production. Due to hurricanes and tropical storms during 2005, the field was
+not productive for approximately 102 days. After repairs of damages caused by Hurricane Rita,
+production was restored in January 2006. The field is currently producing at an average daily
+gross rate of 13.0 MMcfe.
+18
+Table of Contents 
+Oil and Gas Reserves 
+The following table sets forth certain information about our estimated proved reserves as reported
+by Huddleston & Co., Inc. as of the dates set forth below.
+Years Ended December 31, 
+2005 
+2004 
+2003 
+(In thousands) 
+Proved developed: 
+Oil (Bbls) 
+7,323 
+10,292 
+9,919 
+Gas (Mcf) 
+30,982 
+33,982 
+31,415 
+Mcfe 
+74,921 
+95,735 
+90,926 
+Proved undeveloped: 
+Oil (Bbls) 
+11,105 
+9,456 
+13,790 
+Gas (Mcf) 
+47,039 
+38,637 
+43,276 
+Mcfe 
+113,667 
+95,373 
+126,017 
+Total proved: 
+Oil (Bbls) 
+18,428 
+19,748 
+23,709 
+Gas (Mcf) 
+78,021 
+72,619 
+74,691 
+Mcfe 
+188,588 
+191,108 
+216,943 
+Estimated pre-tax future net cash flows (a) 
+$ 
+1,487,817 
+$ 
+892,145 
+$ 
+838,847 
+Pre-tax discounted present value (a) 
+$ 
+1,088,714 
+$ 
+612,595 
+$ 
+570,463 
+Standardized measure of discounted future
+net cash flows(a) 
+$ 
+837,552 
+$ 
+515,893 
+$ 
+519,026 
+(a) 
+Includes a reduction for estimated plugging and abandonment costs that is reflected as
+a liability on our balance sheet at December 31, 2005, in accordance with SFAS 143. 
+Our independent reserve engineers, Huddleston & Co., Inc., prepared the estimates of the proved
+reserves and the future net cash flows and present value thereof attributable to such proved
+reserves. Reserves were estimated using oil and gas prices and production and development costs in
+effect on December 31 of each
+19
+Table of Contents 
+such year, without escalation, and were otherwise prepared in
+accordance with SEC regulations regarding disclosure of oil and gas reserve information.
+There are numerous uncertainties inherent in estimating quantities of proved reserves, including
+many factors beyond our control or the control of the reserve engineers. Reserve engineering is a
+subjective process of estimating underground accumulations of oil and gas that cannot be measured
+in an exact manner. The accuracy of any reserve or cash flow estimate is a function of the quality
+of available data and of engineering and geological interpretation and judgment. Estimates by
+different engineers often vary, sometimes significantly. In addition, physical factors, such as
+the results of drilling, testing and production subsequent to the date of an estimate, as well as
+economic factors, such as an increase or decrease in product prices that renders production of such
+reserves more or less economic, may justify revision of such estimates. Accordingly, reserve
+estimates could be different from the quantities of oil and gas that are ultimately recovered.
+We have not filed any reports with other federal agencies which contain an estimate of total proved
+net oil and gas reserves during our last fiscal year.
+Present Activities and Productive Wells 
+The following table sets forth the wells we have drilled and completed during the periods
+indicated. All such wells were drilled in the continental United States primarily in federal and
+state waters in the Gulf of Mexico.
+Years Ended December 31, 
+2005 
+2004 
+2003 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development: 
+Oil 
+1 
+0.15 
+— 
+— 
+2 
+.23 
+Gas 
+— 
+— 
+2 
+1.22 
+— 
+— 
+Non-productive 
+— 
+— 
+— 
+— 
+— 
+— 
+Total 
+1 
+0.15 
+2 
+1.22 
+2 
+.23 
+Exploration: 
+Oil 
+— 
+— 
+— 
+— 
+1 
+.15 
+Gas 
+7 
+2.42 
+2 
+.72 
+— 
+— 
+Non-productive 
+4 
+1.25 
+5 
+1.24 
+1 
+.20 
+Total 
+11 
+3.67 
+7 
+1.96 
+2 
+.35 
+20
+Table of Contents 
+The following table sets forth our productive wells as of December 31, 2005:
+Wells 
+Gross 
+Net 
+Oil: 
+Working interest 
+39.00 
+3.75 
+Royalty interest 
+192.00 
+3.14 
+Total 
+231.00 
+6.89 
+Gas: 
+Working interest 
+33.00 
+12.70 
+Royalty interest 
+209.00 
+1.58 
+Total 
+242.00 
+14.28 
+A well is categorized as an oil well or a natural gas well based upon the ratio of oil to gas
+reserves on a Mcfe basis. However, some of our wells produce both oil and gas. At December 31,
+2005, we had no wells with multiple completions. At December 31, 2005, 1 gross (0.033 net)
+exploration oil well and 1 gross (0.205 net) exploration gas well were in progress.
+Leasehold Acreage 
+The following table shows our approximate developed and undeveloped (gross and net) leasehold
+acreage as of December 31, 2005.
+Leasehold Acreage 
+Developed 
+Undeveloped 
+Location 
+Gross 
+Net 
+Gross 
+Net 
+Louisiana 
+6,092 
+3,882 
+13,516 
+5,584 
+Texas 
+78 
+— 
+15,870 
+6,680 
+Other states 
+— 
+— 
+681 
+509 
+Federal waters 
+108,102 
+56,770 
+257,140 
+78,523 
+Total 
+114,272 
+60,652 
+287,207 
+91,296 
+As of December 31, 2005, we owned various royalty and overriding royalty interests in 1,336 net
+developed and 6,862 net undeveloped acres. In addition, we owned 4,309 developed and 121,691
+undeveloped mineral acres.
+Major Customers 
+Our production is sold generally on month-to-month contracts at prevailing prices. The following
+table identifies customers to whom we sold a significant percentage of our total oil and gas
+production during each of the 12-month periods ended:
+21
+Table of Contents 
+December 31, 
+2005 
+2004 
+2003 
+Shell Trading Company 
+34 
+% 
+30 
+% 
+— 
+Louis Dreyfus Energy Services 
+16 
+% 
+23 
+% 
+27 
+% 
+Plains Marketing, L.P. 
+16 
+% 
+13 
+% 
+— 
+Chevron Texaco Natural Gas 
+10 
+% 
+6 
+% 
+— 
+Reliant Energy Services 
+— 
+6 
+% 
+28 
+% 
+Prior Energy Corporation 
+— 
+— 
+20 
+% 
+Because alternative purchasers of oil and gas are readily available, we believe that the loss of
+any of these purchasers would not result in a material adverse effect on our ability to market
+future oil and gas production.
+Title to Properties 
+We believe that the title to our oil and gas properties is good and defensible in accordance with
+standards generally accepted in the oil and gas industry, subject to such exceptions which, in our
+opinion, are not so material as to detract substantially from the use or value of such properties.
+Our properties are typically subject, in one degree or another, to one or more of the following:
+• 
+royalties and other burdens and obligations, express or implied, under oil and gas leases; 
+• 
+overriding royalties and other burdens created by us or our predecessors in title; 
+• 
+a variety of contractual obligations (including, in some cases, development obligations)
+arising under operating agreements, farmout agreements, production sales contracts and
+other agreements that may affect the properties or their titles; 
+• 
+back-ins and reversionary interests existing under purchase agreements and leasehold
+assignments; 
+• 
+liens that arise in the normal course of operations, such as those for unpaid taxes,
+statutory liens securing obligations to unpaid suppliers and contractors and contractual
+liens under operating agreements; 
+• 
+pooling, unitization and communitization agreements, declarations and orders; and 
+• 
+easements, restrictions, rights-of-way and other matters that commonly affect property. 
+To the extent that such burdens and obligations affect our rights to production revenues, they have
+been taken into account in calculating our net revenue interests and in estimating the size and
+value of our reserves. We believe that the burdens and obligations affecting our properties are
+conventional in the industry for properties of the kind owned by us.
+22
+Table of Contents 
+ITEM 3. LEGAL PROCEEDINGS 
+We are a defendant in various legal proceedings and claims, which arise in the ordinary course of
+our business. We do not believe the ultimate resolution of any such actions will have a material
+affect on our financial position or results of operations.
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 
+There were no matters submitted to a vote of security holders during the fourth quarter of 2005.
+23
+Table of Contents 
+PART II. 
+ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS 
+Our common stock trades on the New York Stock Exchange under the symbol “CPE”. The following table
+sets forth the high and low sale prices per share as reported for the periods indicated.
+Quarter Ended 
+High 
+Low 
+2004: 
+First quarter 
+$ 
+11.23 
+$ 
+8.70 
+Second quarter 
+14.27 
+10.15 
+Third quarter 
+14.40 
+11.10 
+Fourth quarter 
+14.72 
+12.30 
+2005: 
+First quarter 
+$ 
+18.00 
+$ 
+13.22 
+Second quarter 
+16.12 
+12.42 
+Third quarter 
+21.25 
+14.81 
+Fourth quarter 
+22.29 
+16.65 
+As of March 2, 2006, there were approximately 4,179 common stockholders of record.
+We have never paid dividends on our common stock and intend to retain our cash flow from
+operations, net of preferred stock dividends, for the future operation and development of our
+business. In addition, our primary credit facility and the terms of our outstanding subordinated
+debt prohibit the payment of cash dividends on our common stock.
+ITEM 6. SELECTED FINANCIAL DATA 
+The following table sets forth, as of the dates and for the periods indicated, selected financial
+information about us. The financial information for each of the five years in the period ended
+December 31, 2005 has been derived from our audited Consolidated Financial Statements for such
+periods. The information should be read in conjunction with “Management’s Discussion and Analysis
+of Financial Condition and Results of Operations” and the Consolidated Financial Statements and
+Notes thereto. The following information is not necessarily indicative of our future results.
+24
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+SELECTED HISTORICAL FINANCIAL INFORMATION 
+(In thousands, except per share amounts) 
+Years Ended December 31, 
+2005 
+2004 
+2003 
+2002 
+2001 
+Statement of Operations Data: 
+Operating revenues: 
+Oil and gas sales 
+$ 
+141,290 
+$ 
+119,802 
+$ 
+73,697 
+$ 
+61,171 
+$ 
+60,010 
+Operating expenses: 
+Lease operating expenses 
+24,377 
+22,308 
+11,301 
+11,030 
+11,252 
+Depreciation, depletion and amortization 
+44,946 
+47,453 
+28,253 
+27,096 
+21,081 
+General and administrative 
+8,085 
+8,758 
+4,713 
+4,705 
+4,635 
+Accretion expense 
+3,549 
+3,400 
+2,884 
+— 
+— 
+Derivative expense 
+6,028 
+1,371 
+535 
+708 
+— 
+Total operating expenses 
+86,985 
+83,290 
+47,686 
+43,539 
+36,968 
+Income from operations 
+54,305 
+36,512 
+26,011 
+17,632 
+23,042 
+Other (income) expenses: 
+Interest expense 
+16,660 
+20,137 
+30,614 
+26,140 
+12,805 
+Other (income) 
+(998 
+) 
+(357 
+) 
+(444 
+) 
+(1,004 
+) 
+(1,742 
+) 
+Loss on early extinguishment of debt 
+— 
+3,004 
+5,573 
+— 
+— 
+Gain on sale of pipeline 
+— 
+— 
+— 
+(2,454 
+) 
+— 
+Gain on sale of Enron derivatives 
+— 
+— 
+— 
+(2,479 
+) 
+— 
+Writedown of Enron derivatives 
+— 
+— 
+— 
+— 
+9,186 
+Total other (income) expenses 
+15,662 
+22,784 
+35,743 
+20,203 
+20,249 
+Income (loss) before income taxes 
+38,643 
+13,728 
+(9,732 
+) 
+(2,571 
+) 
+2,793 
+Income tax expense (benefit) 
+13,209 
+(6,697 
+) 
+8,432 
+(900 
+) 
+977 
+Income (loss) before Medusa Spar LLC and
+cumulative effect of change in accounting principle 
+25,434 
+20,425 
+(18,164 
+) 
+(1,671 
+) 
+1,816 
+Income (loss) on Medusa Spar LLC, net of tax 
+1,342 
+1,076 
+(8 
+) 
+— 
+— 
+Income (loss) before cumulative effect of change in
+in accounting principle 
+26,776 
+21,501 
+(18,172 
+) 
+(1,671 
+) 
+1,816 
+Cumulative effect of change in accounting principle,
+net of tax 
+— 
+— 
+181 
+— 
+— 
+Net income (loss) 
+26,776 
+21,501 
+(17,991 
+) 
+(1,671 
+) 
+1,816 
+Preferred stock dividends 
+318 
+1,272 
+1,277 
+1,277 
+1,277 
+Net income (loss) available to common shares 
+$ 
+26,458 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+$ 
+(2,948 
+) 
+$ 
+539 
+25
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+SELECTED HISTORICAL FINANCIAL INFORMATION 
+(In thousands, except per share amounts) 
+Years Ended December 31, 
+2005 
+2004 
+2003 
+2002 
+2001 
+Net income (loss) available to common shares 
+$ 
+26,458 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+$ 
+(2,948 
+) 
+$ 
+539 
+Net income (loss) per common share: 
+Basic: 
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+1.43 
+$ 
+1.28 
+$ 
+(1.42 
+) 
+$ 
+(.22 
+) 
+$ 
+.04 
+Cumulative effect of change in accounting principle,
+net of tax 
+— 
+— 
+.01 
+— 
+— 
+Net income (loss) available to common 
+$ 
+1.43 
+$ 
+1.28 
+$ 
+(1.41 
+) 
+$ 
+(.22 
+) 
+$ 
+.04 
+Diluted: 
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+1.28 
+$ 
+1.22 
+$ 
+(1.42 
+) 
+$ 
+(.22 
+) 
+$ 
+.04 
+Cumulative effect of change in accounting principle,
+net of tax 
+— 
+— 
+.01 
+— 
+— 
+Net income (loss) available to common 
+$ 
+1.28 
+$ 
+1.22 
+$ 
+(1.41 
+) 
+$ 
+(.22 
+) 
+$ 
+.04 
+Shares used in computing net income (loss) per common share: 
+Basic 
+18,453 
+15,796 
+13,662 
+13,387 
+13,273 
+Diluted 
+20,883 
+17,678 
+13,662 
+13,387 
+13,366 
+Balance Sheet Data (end of period): 
+Oil and gas properties, net 
+$ 
+447,364 
+$ 
+406,690 
+$ 
+390,163 
+$ 
+377,661 
+$ 
+343,158 
+Total assets 
+$ 
+533,776 
+$ 
+457,523 
+$ 
+496,032 
+$ 
+410,613 
+$ 
+372,095 
+Long-term debt, less current portion 
+$ 
+188,813 
+$ 
+192,351 
+$ 
+214,885 
+$ 
+248,269 
+$ 
+161,733 
+Stockholders’ equity 
+$ 
+228,048 
+$ 
+198,312 
+$ 
+133,261 
+$ 
+140,960 
+$ 
+147,224 
+We use the full-cost method of accounting. Under this method of accounting, our net
+capitalized costs to acquire explore and develop oil and gas properties may not exceed the
+standardized measure of our proved reserves. If these capitalized costs exceed a ceiling amount,
+the excess is charged to expense.
+26
+Table of Contents 
+ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+The following discussion is intended to assist in an understanding of our financial condition and
+results of operations. Our Consolidated Financial Statements and Notes thereto contain detailed
+information that should be referred to in conjunction with the following discussion. See Item 8.
+“Financial Statements and Supplementary Data.”
+General 
+We have been engaged in the exploration, development, acquisition and production of oil and gas
+properties since 1950. Our revenues, profitability and future growth and the carrying value of our
+oil and gas properties are substantially dependent on prevailing prices of oil and gas and our
+ability to find, develop and acquire additional oil and gas reserves that are economically
+recoverable. Our ability to maintain or increase our borrowing capacity and to obtain additional
+capital on attractive terms is also influenced by oil and gas prices.
+Significant events of our financial and operating results for the year ended December 31, 2005
+included an increase in the borrowing base from $60 million to $70 million, production downtime in
+the third and fourth quarter associated with the tropical storm activity and the redemption of all
+our outstanding shares of $2.125 Convertible Exchange Preferred Stock, Series A. As a result of
+the redemption, we will benefit from an annual cash savings of $1.3 million in dividend payments.
+We expect that planned 2006 capital expenditures of approximately $125 million will be funded with
+cash flows from operations and supplemented, if necessary, with our senior secured credit facility
+which had $62.5 million available on December 31, 2005. For a more detailed discussion of
+outstanding debt see Note 5 to our Consolidated Financial Statements.
+Our estimated net proved oil and gas reserves decreased at December 31, 2005 to 188.6 Bcfe. This
+represents a decrease of 1% from previous year-end 2004 estimated proved reserves of 191.1 Bcfe.
+We produced 18.8 Mmcfe and had net reserve additions of 16.3 Mmcfe.
+Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in
+the supply of and demand for oil and gas, market uncertainty and a variety of additional factors
+beyond our control. These factors include weather conditions in the United States, the condition
+of the United States economy, the actions of the Organization of Petroleum Exporting Countries,
+governmental regulation, political stability in the Middle East and elsewhere, the foreign supply
+of crude oil and natural gas, the price of foreign imports and the availability of alternate fuel
+sources. Any substantial and extended decline in the price of crude oil or natural gas would have
+an adverse effect on our carrying value of our proved reserves, borrowing capacity, revenues,
+profitability and cash flows from operations. We use derivative financial instruments (see Note 6
+to our Consolidated Financial Statements and Item 7A. “Quantitative and Qualitative Disclosures
+About Market Risks”) for price protection purposes on a limited amount of our future production and
+do not use them for trading purposes. On a Mcfe basis, natural gas represents approximately 58% of
+the budgeted 2006 production and 41% of proved reserves at year-end 2005.
+Inflation has not had a material impact on us and is not expected to have a material impact on us
+in the future.
+27
+Table of Contents 
+Summary of Significant Accounting Policies 
+On December 16, 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised
+2004), Share-Based Payment (“SFAS 123R”), which is a revision of Statement of Financial Accounting
+Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”). SFAS 123R supersedes
+APB Opinion No. 25, “Accounting for Stock Issued to Employees”, and amends Statement of Financial
+Accounting Standards No. 95, “Statement of Cash Flows”. Generally, the approach in SFAS 123R is
+similar to the approach described in SFAS 123. However, SFAS 123R requires all share-based
+payments to employees, including grants of employee stock options, to be recognized in the income
+statement based on their fair values. Pro forma disclosure is no longer an alternative.
+In April 2005, the SEC delayed the effective date of SFAS 123R for public companies to no later
+than the beginning of the first fiscal year beginning after June 15, 2005. Early adoption will be
+permitted in periods in which financial statements have not yet been issued. SFAS 123R permits
+public companies to adopt its requirements using one of two methods below:
+• 
+A “modified prospective” method in which compensation cost is recognized beginning with
+the effective date (a) based on the requirements of SFAS 123R for all share-based payments
+granted after the effective date and (b) based on the requirements of SFAS 123 for all
+awards granted to employees prior to the effective date of SFAS 123R that remain unvested
+on the effective date; or 
+• 
+A “modified retrospective” method which includes the requirements of the modified
+prospective method described above, but also permits entities to restate based on the
+amounts previously recognized under SFAS 123 for purposes of pro forma disclosures either
+(a) all prior periods presented or (b) prior interim periods of the year of adoption. 
+As permitted by SFAS 123, we currently account for share-based payments to employees using APB
+Opinion 25’s intrinsic value method and, as such, generally recognize no compensation cost for
+employee stock options. Accordingly, the adoption of SFAS 123R’s fair value method could have a
+significant impact on our result of operations, although it will have no impact on our overall
+financial position. The impact of adoption of SFAS 123R cannot be predicted at this time because
+it will depend on levels of share-based payments granted in the future. However, had we adopted
+SFAS 123R in prior periods, the impact of that standard would have approximated the impact of SFAS
+123 as described in the disclosure of pro forma net income and earnings per share in Note 2 to our
+Consolidated Financial Statements. We adopted SFAS 123R on January 1, 2006 using the modified
+prospective method.
+Property and Equipment. We follow the full-cost method of accounting for oil and gas properties
+whereby all costs incurred in connection with the acquisition, exploration and development of oil
+and gas reserves, including certain overhead costs, are capitalized into the “full-cost pool.” The
+amounts we capitalize into the full-cost pool are depleted (charged against earnings) using the
+unit-of-production method. The full-cost method of accounting for our proved oil and gas
+properties requires that we make estimates based on assumptions as to future events which could
+change. These estimates are described below.
+28
+Table of Contents 
+Depreciation, Depletion and Amortization (DD&A) of Oil and Gas Properties . We calculate depletion
+by using the capitalized costs in our full-cost pool plus future development and abandonment costs
+(combined, the depletable base) and our estimated net proved reserve quantities. Capitalized
+costs added to the full-cost pool and other costs added to the depletable base include the
+following:
+• 
+the cost of drilling and equipping productive wells, dry hole costs, acquisition costs
+of properties with proved reserves, delay rentals and other costs related to exploration
+and development of our oil and gas properties; 
+• 
+our payroll and general and administrative costs and costs related to fringe benefits
+paid to employees directly engaged in the acquisition, exploration and/or development of
+oil and gas properties as well as other directly identifiable general and administrative
+costs associated with such activities. Such capitalized costs do not include any costs
+related to our production of oil and gas or our general corporate overhead; 
+• 
+costs associated with properties that do not have proved reserves attributed to them are
+excluded from the full-cost pool. These unevaluated property costs are added to the
+full-cost pool at such time as wells are completed on the properties, the properties are
+sold or we determine these costs have been impaired. Our determination that a property has
+or has not been impaired (which is discussed below) requires that we make assumptions about
+future events; 
+• 
+our estimates of future costs to develop proved properties are added to the full-cost
+pool for purposes of the DD&A computation. We use assumptions based on the latest
+geologic, engineering, regulatory and cost data available to us to estimate these amounts.
+However, the estimates we make are subjective and may change over time. Our estimates of
+future development costs are periodically updated as additional information becomes
+available; and 
+• 
+prior to the adoption of SFAS 143, estimated costs to dismantle, abandon and restore a
+proved property were added to the full-cost pool for the purposes of DD&A. Subsequent to
+the adoption of SFAS 143, effective January 1, 2003, these costs are included in the
+full-cost pool. Such cost estimates are periodically updated as additional information
+becomes available. As discussed below specifically SFAS 143, beginning January 1, 2003, we
+changed the method for which we account for such costs. 
+Capitalized costs included in the full-cost pool are depleted and charged against earnings using
+the unit of production method. Under this method, we estimate our quantity of proved reserves at
+the beginning of each accounting period. For each barrel of oil equivalent produced during the
+period, we record a depletion charge equal to the amount included in the depletable base (net of
+accumulated depreciation, depletion and amortization) divided by our estimated net proved reserve
+quantities.
+Because we use estimates and assumptions to calculate proved reserves (as discussed below) and the
+amounts included in the full-cost pool, our depletion calculations will change if the estimates and
+assumptions are not realized. Such changes may be material.
+Ceiling Test . Under the full-cost accounting rules, capitalized costs included in the full-cost
+pool, net of accumulated depreciation, depletion and amortization (DD&A), cost of unevaluated
+properties and deferred income taxes, may not exceed the present value of our estimated future net
+cash flows from proved oil and gas reserves, discounted at 10%, plus the lower of cost or fair
+value of unproved properties included in the costs being amortized, net of related tax effects.
+These rules generally require that, in estimating future net cash flow, we assume that future oil
+and gas production will be sold at the unescalated market price for oil and gas received at the end
+of each fiscal quarter and that future costs to produce oil and gas will remain constant at the
+prices in effect at the end of the fiscal quarter. We are required to write-down and charge to
+29
+Table of Contents 
+earnings the amount, if any, by which these costs exceed the discounted future net cash flows,
+unless prices recover sufficiently before the date of our financial statements. Given the
+volatility of oil and gas prices, it is likely that our estimates of
+discounted future net cash flows from proved oil and gas reserves will change in the near term. If
+oil and gas prices decline significantly, even if only for a short period of time, it is possible
+that writedowns of oil and gas properties could occur in the future.
+Estimating Reserves and Present Values . The estimates of quantities of proved oil and gas reserves
+and the discounted present value of such reserves at the end of each quarter are based on numerous
+assumptions which are likely to change over time. These assumptions include:
+• 
+the prices at which we can sell our oil and gas production in the future. Oil and gas
+prices are volatile, but we are generally required to assume that they will not change from
+the prices in effect at the end of the quarter. In general, higher oil and gas prices will
+increase quantities of proved reserves and the present value of such reserves, while lower
+prices will decrease these amounts. Because our properties have relatively short
+productive lives, changes in prices will affect the present value more than quantities of
+oil and gas reserves; 
+• 
+the costs to develop and produce our reserves and the costs to dismantle our production
+facilities when reserves are depleted. These costs are likely to change over time, but we
+are required to assume that costs in effect at the end of the quarter will not change.
+Increases in costs will reduce oil and gas quantities and present values, while decreases
+in costs will increase such amounts. Because our properties have relatively short
+productive lives, changes in costs will affect the present value more than quantities of
+oil and gas reserves; and 
+• 
+the liability to pay royalties to the Mineral Management Service. See Note 7 of our
+Consolidated Financial Statements for a more detailed discussion of this potential
+liability. 
+In addition, the process of estimating proved oil and gas reserves requires that our independent
+and internal reserve engineers exercise judgment based on available geological, geophysical and
+technical information. We have described the risks associated with reserve estimation and the
+volatility of oil and gas prices, under “Risk Factors”.
+Unproved Properties . Costs associated with properties that do not have proved reserves, including
+capitalized interest, are excluded from the full-cost pool. These unproved properties are included
+in the line item “Unevaluated properties excluded from amortization.” Unproved property costs are
+transferred to the full-cost pool when wells are completed on the properties or the properties are
+sold. In addition, we are required to determine whether our unproved properties are impaired and,
+if so, add the costs of such properties to the full-cost pool. We determine whether an unproved
+property should be impaired by periodically reviewing our exploration program on a property by
+property basis. This determination may require the exercise of substantial judgment by our
+management.
+Asset Retirement Obligations. In June 2001, the FASB issued SFAS 143 effective for fiscal years
+beginning after June 15, 2002. SFAS 143 essentially requires entities to record the fair value of
+a liability for obligations associated with the retirement of tangible long-lived assets and the
+associated asset retirement costs. We adopted the statement on January 1, 2003 resulting in a
+cumulative effect of accounting change of $181,000, net of tax. See Note 8 to our Consolidated
+Financial Statements.
+Derivatives. We use derivative financial instruments for price protection purposes on a limited
+amount of our future production and do not use them for trading purposes. Such derivatives were
+accounted for in years prior to 2001 as hedges and have been recognized as an adjustment to oil and
+gas sales in the period in which they are related. We currently use the accounting treatment for
+derivatives specified under SFAS 133.
+30
+Table of Contents 
+See Note 6 to our Consolidated Financial Statements.
+Income Taxes. We follow the asset and liability method of accounting for deferred income taxes
+prescribed by Statement of Financial Accounting Standards No. 109 (“SFAS 109”) “Accounting for
+Income Taxes”. The statement provides for the recognition of a deferred tax asset for deductible
+temporary timing differences, capital and operating loss carryforwards, statutory depletion
+carryforward and tax credit carryforwards, net of a “valuation allowance”. The valuation allowance
+is provided for that portion of the asset, for which it is deemed more likely than not, that it
+will not be realized.
+SFAS 109 provides for the weighing of positive and negative evidence in determining whether it is
+more likely than not that a deferred tax asset is recoverable. We incurred losses in 2002 and 2003
+and had losses on an aggregate basis for the three-year period ended December 31, 2003. Because of
+these cumulative losses we established a full valuation allowance of $11.5 million as of December
+31, 2003.
+As a result of production from our first two deepwater projects starting in November 2003, as well
+as refinancing our highest cost debt in 2004, we achieved profitable operations and had income on
+an aggregate basis for the three-year period ended December 31, 2004. As a result, we reversed the
+valuation allowance in 2004 which had a balance of $7.0 million as of December 31, 2004. See Note
+3 to the Consolidated Financial Statements for further disclosure.
+Liquidity and Capital Resources 
+Historically, our primary sources of capital have been cash flows from operations, borrowings from
+financial institutions and the sale of debt and equity securities. Net cash and cash equivalents
+decreased during 2005 to $2.6 million, down $0.7 million. Cash provided from operating activities
+during 2005 totaled $74 million, up 4% from $71 million in 2004. Dividends paid on preferred stock
+in 2005 were $318,000.
+On June 15, 2004, we closed on a three-year senior secured credit facility underwritten by Union
+Bank of California, N.A. The credit facility includes a borrowing base, determined by the lender,
+of $70 million, which may be adjusted semi-annually and could increase to a maximum of $175
+million. As of December 31, 2005 there were no borrowings outstanding under the facility and we
+had an aggregate of $7.5 million in outstanding letters of credit issued under the credit facility.
+These letters of credit secure obligations under the outstanding hedging contracts described in
+Note 6 to the Consolidated Financial Statements. The outstanding letters of credit reduce the
+amount available for borrowings under the credit facility. As a result, $62.5 million was
+available for future borrowings under the credit facility as of December 31, 2005.
+In December 2003 and March 2004, we closed on our 9.75% senior notes due 2010 in the aggregate
+principal amount of $200 million. The net proceeds from these notes and the public offering of
+3,450,000 shares of common stock in the second quarter of 2004 were used to restructure our debt
+that was maturing in 2004 and 2005. See Note 5 to the Consolidated Financial Statements for a more
+detailed discussion of our debt restructure.
+The indenture governing our 9.75% senior notes due 2010 and our senior secured credit facility
+contain various covenants including restrictions on additional indebtedness and payment of cash
+dividends. In addition, our senior secured credit facility contains covenants for maintenance of
+certain financial ratios. We were in compliance with these covenants at December 31, 2005.
+31
+Table of Contents 
+Our oil and gas reserves as reported by Huddleston & Co., Inc. were 189 Bcfe of natural gas
+equivalents on December 31, 2005. Our cash flow from operations during 2005 was generated by the
+production of 18.8 Bcfe after incurring significant downtime at our major producing properties due
+to tropical storms
+and hurricanes during the last half of the year. Production of our reserves during 2006, without
+weather-related downtime, is projected to be higher than 2005 due to eight new discoveries
+scheduled to commence initial production during 2006 which will offset traditional declines from
+our current producing properties.
+Our planned capital expenditures for 2006 total $125 million. The current portion of our asset
+retirement obligation in the amount of $21.7 million and capitalized interest and general and
+administrative expenses are included in the $125 million. Capital expenditure plans for 2006
+include:
+• 
+the completion and development of pre-2006 shelf discoveries; 
+• 
+the discretionary drilling of approximately 18 shelf and onshore exploratory wells; 
+• 
+drilling of three deepwater prospects; 
+• 
+lease and seismic acquisition; and 
+• 
+capitalized interest and overhead. 
+We believe that our operating cash flow and our credit facility will be adequate to meet our
+capital, debt repayment, and operating requirements for 2006. We fund our day-to-day operating
+expenses and capital expenditures from operating cash flows, supplemented as needed by borrowings
+under our credit facility. In addition, we have sold debt and equity in both public and private
+offerings in the past, and we expect that these sources of capital will continue to be available to
+us in the future. Because of the liquidity and capital resources alternatives available to us,
+including internally generated cash flows, our management believes that our short-term and
+long-term liquidity is adequate to fund operations, including our capital spending program,
+repayment of maturing debt and any amounts that may ultimately be paid in connection with
+contingencies.
+Our cash flow, both in the short and long-term, is impacted by highly volatile oil and natural gas
+prices, production levels, industry trends impacting operating expenses and our ability to continue
+to acquire or find reserves at competitive prices. Cash flow forecasts for internal use by
+management are revised monthly in response to changing market conditions and production
+projections. We routinely adjust capital expenditure budgets within the planned total amount in
+response to the adjusted cash flow forecasts and market trends in drilling and acquisitions costs.
+32
+Table of Contents 
+The following table describes our outstanding contractual obligations (in thousands) as of December
+31, 2005:
+Payments due by Period 
+More 
+Contractual 
+Less Than 
+One-Three 
+Three-Five 
+Than-Five 
+Obligations 
+Total 
+One Year 
+Years 
+Years 
+Years 
+Senior Secured Credit Facility 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+9.75% Senior Notes 
+200,000 
+— 
+— 
+200,000 
+— 
+Capital lease (future minimum payments) 
+1,710 
+439 
+577 
+449 
+245 
+Throughput Commitments: 
+Medusa Spar LLC 
+12,684 
+3,836 
+5,532 
+3,316 
+— 
+Medusa Oil Pipeline 
+606 
+206 
+186 
+113 
+101 
+$ 
+215,000 
+$ 
+4,481 
+$ 
+6,295 
+$ 
+203,878 
+$ 
+346 
+Off-Balance Sheet Arrangements 
+In December 2003, we announced the formation of a limited liability company, Medusa Spar LLC, which
+now owns a 75% undivided ownership interest in the deepwater spar production facilities on our
+Medusa Field in the Gulf of Mexico. We contributed a 15% undivided ownership interest in the
+production facility to Medusa Spar LLC in return for approximately $25 million in cash and a 10%
+ownership interest in the LLC. The LLC will earn a tariff based upon production volume throughput
+from the Medusa area. We are obligated to process our share of production from the Medusa Field and
+any future discoveries in the area through the spar production facilities. This arrangement allows
+us to defer the cost of the spar production facility over the life of the Medusa Field. Our cash
+proceeds were used to reduce the balance outstanding under our senior secured credit facility. The
+LLC used the cash proceeds from $83.7 million of non-recourse financing and a cash contribution by
+one of the LLC owners to acquire its 75% interest in the spar. On December 31, 2005, $47.0 million
+of the financing was outstanding. The balance of Medusa Spar LLC is owned by Oceaneering
+International, Inc. and Murphy. We are accounting for our 10% ownership interest in the LLC under
+the equity method.
+2005 Hurricane Activity 
+During 2005, we encountered numerous tropical storms and hurricanes which caused all of our fields
+located in the Gulf of Mexico area to be shut-in at various times during the year. Hurricanes
+Katrina and Rita, being the most devastating of these tropical weather systems, caused substantial
+downtime in the third and fourth quarter of 2005 which was primarily due to damage incurred to oil
+and gas transmission lines and production facilities owned by third parties.
+Our major fields, Medusa, Habanero and Mobile Bay Blocks 863, 864, 907, 953 and 955, incurred
+damage; but the fields were repaired and brought back online in the fourth quarter of 2005. Our
+properties are insured and we expect to get reimbursed for most of our costs incurred for damage
+repairs, less our $250,000 deductible per occurrence. We estimated that our cost to repair the
+hurricane damages will be approximately $4.0 million. As of December 31, 2005, we had expensed
+$1.2 million for damages related to tropical storms and hurricanes for deductibles and the costs of
+repairs not covered by our property insurance carrier.
+33
+Table of Contents 
+The tropical storms and hurricanes during 2005 had a significant impact on our cash flows from
+properties. Scheduled below are our major properties which incurred lost production days:
+Field 
+Production Days Lost 
+Medusa 
+102 
+Habanero 
+85 
+Mobile Block 864 Unit 
+48 
+Mobile 953 
+48 
+Mobile 955 
+136 
+High Island 119 
+102 
+These properties account for 86% of our production for 2005. In addition, initial production from
+our recent discoveries at North Padre Island Block 913 and East Cameron Block 90 were delayed due
+to equipment availability problems. See “Significant Properties” for more detail by property.
+We are in the process of negotiating our insurance renewal for the year ended March 31, 2007. We
+expect our insurance premiums to increase but can not estimate the amount at this time.
+34
+Table of Contents 
+Results of Operations 
+The following table sets forth certain operating information with respect to our oil and gas
+operations for each of the three years in the period ended December 31, 2005.
+December 31, 
+2005 
+2004 
+2003 
+Production: 
+Oil (MBbls) 
+1,837 
+1,736 
+268 
+Gas (MMcf) 
+7,768 
+11,387 
+12,315 
+Total production (MMcfe) 
+18,787 
+21,801 
+13,923 
+Average daily production (MMcfe) 
+51.5 
+59.6 
+38.1 
+Average sales price: 
+Oil (per Bbl) (a) 
+$ 
+41.61 
+$ 
+28.71 
+$ 
+28.72 
+Gas (per Mcf) 
+$ 
+8.35 
+$ 
+6.15 
+$ 
+5.36 
+Total (per Mcfe) 
+$ 
+7.52 
+$ 
+5.50 
+$ 
+5.29 
+Oil and Gas revenues (in thousands): 
+Oil revenue 
+$ 
+76,425 
+$ 
+49,826 
+$ 
+7,696 
+Gas revenue 
+64,865 
+69,976 
+66,001 
+Total 
+$ 
+141,290 
+$ 
+119,802 
+$ 
+73,697 
+Oil and gas production costs (in thousands): 
+Lease operating expenses 
+$ 
+24,377 
+$ 
+22,308 
+$ 
+11,301 
+Additional per Mcfe data: 
+Sales price 
+$ 
+7.52 
+$ 
+5.50 
+$ 
+5.29 
+Lease operating expenses 
+1.30 
+1.02 
+.81 
+Operating margin 
+$ 
+6.22 
+$ 
+4.48 
+$ 
+4.48 
+Depletion 
+$ 
+2.39 
+$ 
+2.18 
+$ 
+2.03 
+Accretion 
+$ 
+.19 
+$ 
+.16 
+$ 
+.21 
+General and administrative (net of management fees) 
+$ 
+.43 
+$ 
+.40 
+$ 
+.34 
+(a) Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil: 
+Average NYMEX oil price 
+$ 
+56.57 
+$ 
+41.38 
+$ 
+31.08 
+Basis differential and quality adjustments 
+(8.45 
+) 
+(4.60 
+) 
+(1.94 
+) 
+Transportation 
+(1.26 
+) 
+(1.27 
+) 
+(0.42 
+) 
+Hedging 
+(5.25 
+) 
+(6.80 
+) 
+— 
+Average realized oil price 
+$ 
+41.61 
+$ 
+28.71 
+$ 
+28.72 
+35
+Table of Contents 
+Comparison of Results of Operations for the Years Ended December 31, 2005 and 2004 
+Oil and Gas Revenues 
+Total oil and gas revenues increased 18% from $119.8 million in 2004 to $141.3 million in 2005
+primarily due to pricing. Total production for 2005 decreased by 14% versus 2004 as a result of
+downtime associated with the tropical storm and hurricane activity in 2005.
+Gas production during 2005 totaled 7.8 Bcf and generated $64.9 million in revenues compared to 11.4
+Bcf and $70.0 million in revenues during the same period in 2004. Average gas prices realized for
+2005 were $8.35 per Mcf compared to $6.15 per Mcf during the same period last year. The decrease
+in production was primarily due to significant downtime related to tropical storm and hurricane
+activity and the normal and expected decline in production from our Mobile area fields and older
+properties. See our discussion of “Significant Properties” for a more detailed discussion by
+property of this downtime.
+Oil production during 2005 totaled 1,837,000 barrels and generated $76.4 million in revenues
+compared to 1,736,000 barrels and $49.8 million in revenues for the same period in 2004. Average
+oil prices realized in 2005 were $41.61 per barrel compared to $28.71 per barrel in 2004. Oil
+production increased during 2005 despite significant downtime resulting from tropical storms and
+hurricanes. The increase was primarily attributable to our deepwater property Medusa which began
+production in 2003 from a single well with five others being brought online during 2004 and all six
+producing during 2005. In addition, our North Medusa discovery was completed and initial
+production commenced through the field facilities in April 2005. See our discussion of
+“Significant Properties” for more detail regarding production and downtime.
+Lease Operating Expenses 
+Lease operating expenses for 2005 increased by 9% to $24.4 million compared to $22.3 million for
+the same period in 2004. The increase was primarily due to lease operating expenses related to our
+deepwater discovery, Medusa, which had higher throughput charges as a result of higher production
+rates and the addition of our High Island Block 119 field, which began producing late in the third
+quarter of 2004.
+In addition, lease operating expenses for 2005 included the costs of repairs to our properties for
+damages caused by tropical storms and hurricanes in the net amount of $1.2 million. This amount
+covers the deductibles and an estimate of repairs not expected to be reimbursed by our property
+insurance carrier.
+Depreciation, Depletion and Amortization 
+Depreciation, depletion and amortization for 2005 and 2004 were $44.9 million and $47.5 million,
+respectively. The 5% decrease was primarily due to lower production volumes for 2005 compared to
+2004. The decrease was partially offset by a higher average depletion rate.
+Accretion Expense 
+Accretion expense for 2005 and 2004 of $3.5 million and $3.4 million, respectively, represents
+accretion for our asset retirement obligations. The increase was due to the addition of plugging
+and abandonment obligations. See Note 8 to the Consolidated Financial Statements.
+36
+Table of Contents 
+General and Administrative 
+General and administrative expenses for 2005, net of amounts capitalized, were $8.1 million
+compared to $8.8 million incurred in 2004. There was a charge in general and administrative
+expenses of $2.6 million in the first
+quarter of 2004 for the early retirement of two executive officers of the Company. The decrease
+was partially offset by reduced capitalized overhead for 2005 and a non-cash charge during the
+second quarter of 2005 for the accelerated vesting of performance shares in the amount of $930,000
+for an executive officer and two directors of the Company, two of whom are deceased.
+Interest Expense 
+Interest expense decreased by 17% in 2005 to $16.7 million compared to $20.1 million in 2004. This
+decrease is primarily attributable to an equity offering completed in the second quarter of 2004 in
+which a portion of the proceeds were used to redeem $33 million of 11% Senior Subordinated Notes .
+Loss on Early Extinguishment of Debt 
+A loss of $3.0 million was incurred in 2004 for the write-off of deferred financing costs,
+pre-payment premiums and bond discounts associated with the early extinguishment of debt.
+Income Taxes 
+For 2005, we had an income tax expense of $13.2 million compared to an income tax benefit of $6.7
+million in 2004. The income tax benefit for 2004 resulted primarily from the reversal of the
+valuation allowance established in 2003 against our deferred tax asset. As a result of production
+from the Company’s first two deepwater projects starting in November 2003, as well as refinancing
+its highest cost debt in 2004, the Company achieved profitable operations and has income on an
+aggregate basis for the three-year period ended December 31, 2004 and the Company reversed the
+valuation allowance. See Note 3 to our Consolidated Financial Statements for a more detailed
+discussion.
+37
+Table of Contents 
+Comparison of Results of Operations for the Years Ended December 31, 2004 and 2003 
+Oil and Gas Revenues 
+Total production for 2004 increased by 57% versus 2003 and total oil and gas revenues increased 63%
+from $73.7 million in 2003 to $119.8 million in 2004. Increased production was primarily due to our
+deepwater discoveries, Medusa and Habanero, which began producing late in the fourth quarter of
+2003.
+Gas production during 2004 totaled 11.4 Bcf and generated $70.0 million in revenues compared to
+12.3 Bcf and $66.0 million in revenues during the same period in 2003. Average gas prices realized
+for 2004 were $6.15 per Mcf compared to $5.36 per Mcf during the same period the previous year.
+The decrease in production was primarily due to downtime for Hurricane Ivan and the normal and
+expected decline in production from our Mobile area fields and older properties. These factors
+were partially offset by production from Medusa and Habanero.
+Oil production during 2004 totaled 1,736,000 barrels and generated $49.8 million in revenues
+compared to 268,000 barrels and $7.7 million in revenues for the same period in 2003. Average oil
+prices realized in 2004 were $28.71 per barrel compared to $28.72 per barrel in 2003. The increase
+in production was due to the initial production from our deepwater discoveries, Medusa and
+Habanero. The production increase was offset slightly by downtime for Hurricane Ivan and normal
+and expected declines in production from older properties.
+Lease Operating Expenses 
+Lease operating expenses for 2004 increased by 97% to $22.3 million compared to $11.3 million for
+the same period in 2003. The increase was primarily due to lease operating expenses related to our
+deepwater discoveries, Medusa and Habanero.
+Depreciation, Depletion and Amortization 
+Depreciation, depletion and amortization for 2004 and 2003 were $47.5 million and $28.3 million,
+respectively. The 68% increase was primarily due to higher production volumes for 2004 compared to
+2003.
+Accretion Expense 
+Accretion expense for 2004 and 2003 of $3.4 million and $2.9 million, respectively, represents
+accretion for our asset retirement obligations. The increase was due to the addition of plugging
+and abandonment obligations. See Note 8 to the Consolidated Financial Statements.
+General and Administrative 
+General and administrative expenses for 2004, net of amounts capitalized, were $8.8 million
+compared to $4.7 million incurred in 2003. There was a charge in general and administrative
+expenses of $2.6 million in the first quarter of 2004 for the early retirement of two executive
+officers of the Company. Also reduced capitalized overhead, higher directors’ fees, and increased
+independent and internal audit costs resulting from the implementation of The Sarbanes-Oxley Act,
+Section 404 contributed to the increase in general and administrative expenses.
+38
+Table of Contents 
+Interest Expense 
+Interest expense decreased by 34% in 2004 to $20.1 million compared to $30.6 million in 2003. This
+is a result of lower debt levels and lower interest rates due to the restructuring of debt in
+December 2003 and during the six-month period ended June 30, 2004 in additional to an equity
+offering completed in the
+second quarter of 2004. In addition, amortization of deferred financing costs and bond discounts
+decreased due to the write-off of unamortized deferred financing costs and bond discounts
+associated with the early extinguishment of debt.
+Loss on Early Extinguishment of Debt 
+A loss of $3.0 million and $5.6 million was incurred in 2004 and 2003, respectively. Both were
+incurred for the write-off of deferred financing costs, pre-payment premiums and bond discounts
+associated with the early extinguishment of debt.
+Income Taxes 
+The income tax benefit of $6.7 million in 2004 resulted primarily from the reversal of the
+valuation allowance established in 2003 against our deferred tax asset. As a result of production
+from the Company’s first two deepwater projects starting in November 2003, as well as refinancing
+its highest cost debt in 2004, the Company achieved profitable operations and has income on an
+aggregate basis for the three-year period ended December 31, 2004 and the Company reversed the
+valuation allowance. See Note 3 to our Consolidated Financial Statements for a more detailed
+discussion.
+39
+Table of Contents 
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS 
+The Company’s revenues are derived from the sale of its crude oil and natural gas production.
+Recently the prices for oil and gas have increased; however, they remain extremely volatile and
+sometimes experience large fluctuations as a result of relatively small changes in supplies,
+weather conditions,
+economic conditions and government actions. The Company enters into short-term derivative
+financial instruments to hedge oil and gas price risks for the production volumes to which the
+hedge relates. The derivatives reduce the Company’s exposure on the hedged volumes to decreases in
+commodity prices and limit the benefit the Company might otherwise have received from any increases
+in commodity prices on the hedged volumes.
+The Company also enters into price “collars” to reduce the risk of changes in oil and gas prices.
+Under these arrangements, no payments are due by either party so long as the market price is above
+the floor price set in the collar and below the ceiling. If the price falls below the floor, the
+counter-party to the collar pays the difference to the Company and if the price is above the
+ceiling, the counter-party receives the difference from the Company. Another type of hedging
+contract Callon has entered into is a put contract. Under a put, if the price falls below the set
+floor price, the counter-party to the contract pays the difference to the Company. The Company
+enters into these various agreements to reduce the effects of volatile oil and gas prices and does
+not enter into hedge transactions for speculative purposes. See Note 6 to the Consolidated
+Financial Statements for a description of the Company’s hedged position at December 31, 2005.
+There have been no significant changes in market risks faced by the Company since the end of 2005.
+Based on projected annual sales volumes for 2006 (excluding forecast production increases over
+2005), a 10% decline in the prices Callon receives for its crude oil and natural gas production
+would have an approximate $18 million impact on our revenues.
+40
+Table of Contents 
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+Page 
+Report of Independent Registered Public Accounting Firm 
+42 
+Consolidated Balance Sheets as of December 31, 2005
+and 2004 
+43 
+Consolidated Statements of Operations for Each of the Three Years
+in the Period Ended December 31, 2005 
+44 
+Consolidated Statements of Stockholders’ Equity
+for Each of the Three Years in the Period Ended December 31, 2005 
+45 
+Consolidated Statements of Cash Flows for Each of the Three Years
+in the Period Ended December 31, 2005 
+46 
+Notes to Consolidated Financial Statements 
+47 
+41
+Table of Contents 
+Report of Independent Registered Public Accounting Firm
+The Stockholders and Board of Directors 
+Callon Petroleum Company
+We have audited the accompanying consolidated balance sheets of Callon Petroleum Company as of
+December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’
+equity and cash flows for each of the three years in the period ended December 31, 2005. These
+financial statements are the responsibility of the Company’s management. Our responsibility is to
+express an opinion on these financial statements based on our audits.
+We conducted our audits in accordance with the standards of the Public Company Accounting
+Oversight Board (United States). Those standards require that we plan and perform the audit to
+obtain reasonable assurance about whether the financial statements are free of material
+misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
+disclosures in the financial statements. An audit also includes assessing the accounting
+principles used and significant estimates made by management, as well as evaluating the overall
+financial statement presentation. We believe that our audits provide a reasonable basis for our
+opinion.
+In our opinion, the financial statements referred to above present fairly, in all material
+respects, the consolidated financial position of Callon Petroleum Company as of December 31, 2005
+and 2004, and the results of its operations and its cash flows for each of the three years in the
+period ended December 31, 2005, in conformity with U.S.
+generally accepted accounting principles.
+As discussed in Note 1 to the financial statements, effective January 1, 2003, the Company
+adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement
+Obligations”.
+We also have audited, in accordance with the standards of the Public Company Accounting
+Oversight Board (United States), the effectiveness of Callon Petroleum Company’s internal control
+over financial reporting as of December 31, 2005, based on criteria established in Internal
+Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
+Commission and our report dated March 9, 2006, expressed an unqualified opinion thereon.
+/s/Ernst & Young LLP
+New Orleans, Louisiana 
+March 9, 2006
+42
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED BALANCE SHEETS 
+(In thousands, except share data) 
+December 31, 
+2005 
+2004 
+ASSETS 
+Current assets: 
+Cash and cash equivalents 
+$ 
+2,565 
+$ 
+3,266 
+Accounts receivable 
+33,195 
+14,928 
+Deferred tax asset-current 
+26,770 
+5,676 
+Restricted investments-current 
+4,110 
+2,055 
+Fair market value of derivatives 
+889 
+1,570 
+Other current assets 
+1,998 
+581 
+Total current assets 
+69,527 
+28,076 
+Oil and gas properties, full-cost accounting method: 
+Evaluated properties 
+937,698 
+862,101 
+Less accumulated depreciation, depletion and amortization 
+(539,399 
+) 
+(494,453 
+) 
+398,299 
+367,648 
+Unevaluated properties excluded from amortization 
+49,065 
+39,042 
+Total oil and gas properties 
+447,364 
+406,690 
+Other property and equipment, net 
+1,605 
+1,541 
+Deferred tax asset 
+— 
+2,986 
+Long-term gas balancing receivable 
+403 
+725 
+Restricted investments 
+1,858 
+5,687 
+Investment in Medusa Spar LLC 
+11,389 
+9,787 
+Other assets, net 
+1,630 
+2,031 
+Total assets 
+$ 
+533,776 
+$ 
+457,523 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued liabilities 
+$ 
+39,323 
+$ 
+15,728 
+Fair market value of derivatives 
+1,247 
+2,993 
+Undistributed oil and gas revenues 
+721 
+1,162 
+Accrued net profits interest payable 
+— 
+1,927 
+Suspended Medusa oil royalties 
+— 
+5,430 
+Asset retirement obligations-current 
+21,660 
+13,300 
+Current maturities of long-term debt 
+263 
+576 
+Total current liabilities 
+63,214 
+41,116 
+Long-term debt 
+188,813 
+192,351 
+Asset retirement obligations 
+16,613 
+24,982 
+Deferred tax liability 
+31,633 
+— 
+Accrued liabilities to be refinanced 
+5,000 
+— 
+Other long-term liabilities 
+455 
+762 
+Total liabilities 
+305,728 
+259,211 
+Stockholders’ equity: 
+Preferred Stock, $.01 par value; 2,500,000 shares authorized;
+-0- and 596,671 shares of Convertible Exchangeable Preferred
+Stock, Series A issued and outstanding at December 31,
+2005 and 2004, respectively 
+— 
+6 
+Common Stock, $.01 par value; 30,000,000 shares
+authorized; 19,357,138 shares and 17,616,596 shares issued
+and
+outstanding at December 31, 2005 and 2004, respectively 
+194 
+176 
+Unearned compensation-restricted stock 
+(3,334 
+) 
+(5,352 
+) 
+Capital in excess of par value 
+220,360 
+220,664 
+Other comprehensive loss 
+(331 
+) 
+(1,883 
+) 
+Retained earnings (deficit) 
+11,159 
+(15,299 
+) 
+Total stockholders’ equity 
+228,048 
+198,312 
+Total liabilities and stockholders’ equity 
+$ 
+533,776 
+$ 
+457,523 
+The accompanying notes are an integral part of these financial statements.
+43
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Statements of Operations 
+For the Years Ended December 31, 2005, 2004 and 2003 
+(In thousands, except per share amounts) 
+2005 
+2004 
+2003 
+Operating revenues: 
+Oil and gas sales 
+$ 
+141,290 
+$ 
+119,802 
+$ 
+73,697 
+Operating expenses: 
+Lease operating expenses 
+24,377 
+22,308 
+11,301 
+Depreciation, depletion and amortization 
+44,946 
+47,453 
+28,253 
+General and administrative 
+8,085 
+8,758 
+4,713 
+Accretion expense 
+3,549 
+3,400 
+2,884 
+Derivative expense 
+6,028 
+1,371 
+535 
+Total operating expenses 
+86,985 
+83,290 
+47,686 
+Income from operations 
+54,305 
+36,512 
+26,011 
+Other (income) expenses: 
+Interest expense 
+16,660 
+20,137 
+30,614 
+Other (income) 
+(998 
+) 
+(357 
+) 
+(444 
+) 
+Loss on early extinguishment of debt 
+— 
+3,004 
+5,573 
+Total other (income) expenses 
+15,662 
+22,784 
+35,743 
+Income (loss) before income taxes 
+38,643 
+13,728 
+(9,732 
+) 
+Income tax expense (benefit) 
+13,209 
+(6,697 
+) 
+8,432 
+Income (loss) before Medusa Spar LLC and cumulative
+effect of change in accounting principle 
+25,434 
+20,425 
+(18,164 
+) 
+Income (loss) on Medusa Spar LLC, net of tax 
+1,342 
+1,076 
+(8 
+) 
+Income (loss) before cumulative effect of change in
+accounting principle 
+26,776 
+21,501 
+(18,172 
+) 
+Cumulative effect of change in accounting principle, net of tax 
+— 
+— 
+181 
+Net income (loss) 
+26,776 
+21,501 
+(17,991 
+) 
+Preferred stock dividends 
+318 
+1,272 
+1,277 
+Net income (loss) available to common shares 
+$ 
+26,458 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+Net income (loss) per common share: 
+Basic 
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+1.43 
+$ 
+1.28 
+$ 
+(1.42 
+) 
+Cumulative effect of change in accounting principle, net of
+tax 
+— 
+— 
+0.01 
+Net income (loss) available to common share 
+$ 
+1.43 
+$ 
+1.28 
+$ 
+(1.41 
+) 
+Diluted 
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+1.28 
+$ 
+1.22 
+$ 
+(1.42 
+) 
+Cumulative effect of change in accounting principle, net of
+tax 
+— 
+— 
+0.01 
+Net income (loss) available to common share 
+$ 
+1.28 
+$ 
+1.22 
+$ 
+(1.41 
+) 
+Shares used
+in computing net income (loss) per share amounts: 
+Basic 
+18,453 
+15,796 
+13,662 
+Diluted 
+20,883 
+17,678 
+13,662 
+The accompanying notes are an integral part of these financial statements.
+44
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY 
+(In thousands) 
+Unearned 
+Accumulated 
+Total 
+Restricted 
+Capital in 
+Other 
+Retained 
+Stock- 
+Preferred 
+Common 
+Stock 
+Excess of 
+Comprehensive 
+Earnings 
+holders’ 
+Stock 
+Stock 
+Compensation 
+Par Value 
+Income (Loss) 
+(Deficit) 
+Equity 
+Balances, December 31, 2002 
+$ 
+6 
+$ 
+139 
+$ 
+(826 
+) 
+$ 
+158,370 
+$ 
+(469 
+) 
+$ 
+(16,260 
+) 
+$ 
+140,960 
+Comprehensive income (loss): 
+Net loss 
+— 
+— 
+— 
+— 
+— 
+(17,991 
+) 
+Other comprehensive income 
+— 
+— 
+— 
+— 
+449 
+— 
+Total comprehensive loss 
+(17,542 
+) 
+Preferred stock dividends 
+— 
+— 
+— 
+— 
+— 
+(1,277 
+) 
+(1,277 
+) 
+Shares issued pursuant to employee
+benefit and option plan 
+— 
+1 
+— 
+427 
+— 
+— 
+428 
+Employee stock purchase plan 
+— 
+— 
+— 
+127 
+— 
+— 
+127 
+Restricted stock 
+— 
+(1 
+) 
+454 
+(516 
+) 
+— 
+— 
+(63 
+) 
+Warrants 
+— 
+— 
+— 
+10,628 
+— 
+— 
+10,628 
+Balances, December 31, 2003 
+6 
+139 
+(372 
+) 
+169,036 
+(20 
+) 
+(35,528 
+) 
+133,261 
+Comprehensive income (loss): 
+Net income 
+— 
+— 
+— 
+— 
+— 
+21,501 
+Other comprehensive (loss) 
+— 
+— 
+— 
+— 
+(1,863 
+) 
+— 
+Total comprehensive income 
+19,638 
+Preferred stock dividend 
+— 
+— 
+— 
+— 
+— 
+(1,272 
+) 
+(1,272 
+) 
+Sale of common stock 
+— 
+35 
+— 
+44,012 
+— 
+— 
+44,047 
+Shares issued pursuant to employee
+benefit and option plan 
+— 
+1 
+— 
+720 
+— 
+— 
+721 
+Employee stock purchase plan 
+— 
+1 
+— 
+208 
+— 
+— 
+209 
+Tax benefits related to stock
+compensation plans 
+— 
+— 
+— 
+1,214 
+— 
+— 
+1,214 
+Restricted stock 
+— 
+— 
+(4,980 
+) 
+5,474 
+— 
+— 
+494 
+Balances, December 31, 2004 
+6 
+176 
+(5,352 
+) 
+220,664 
+(1,883 
+) 
+(15,299 
+) 
+198,312 
+Comprehensive income (loss): 
+Net income 
+— 
+— 
+— 
+— 
+— 
+26,776 
+Other comprehensive income 
+— 
+— 
+— 
+— 
+1,552 
+— 
+Total comprehensive income 
+28,328 
+Preferred stock dividend 
+— 
+— 
+— 
+— 
+— 
+(318 
+) 
+(318 
+) 
+Conversion of preferred shares
+to common stock 
+(6 
+) 
+13 
+— 
+(643 
+) 
+— 
+— 
+(636 
+) 
+Shares issued pursuant to employee
+benefit and option plan 
+— 
+1 
+— 
+(325 
+) 
+— 
+— 
+(324 
+) 
+Employee stock purchase plan 
+— 
+— 
+— 
+(33 
+) 
+— 
+— 
+(33 
+) 
+Tax benefits related to stock
+compensation plans 
+— 
+— 
+— 
+1,029 
+— 
+— 
+1,029 
+Restricted stock 
+— 
+2 
+2,018 
+(330 
+) 
+— 
+— 
+1,690 
+Warrants 
+— 
+2 
+— 
+(2 
+) 
+— 
+— 
+— 
+Balances, December 31, 2005 
+$ 
+— 
+$ 
+194 
+$ 
+(3,334 
+) 
+$ 
+220,360 
+$ 
+(331 
+) 
+$ 
+11,159 
+$ 
+228,048 
+The accompanying notes are an integral part of these financial statements.
+45
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+For the Years Ended December 31, 2005, 2004 and 2003 
+(In thousands) 
+2005 
+2004 
+2003 
+Cash flows from operating activities: 
+Net income (loss) 
+$ 
+26,776 
+$ 
+21,501 
+$ 
+(17,991 
+) 
+Adjustments to reconcile net income (loss) to
+cash provided by operating activities: 
+Depreciation, depletion and amortization 
+45,657 
+48,164 
+29,264 
+Accretion expense 
+3,549 
+3,400 
+2,884 
+Amortization of deferred financing costs 
+2,062 
+1,929 
+6,568 
+Non-cash loss on extinguishment of debt 
+— 
+2,910 
+4,423 
+Income from investment in Medusa Spar, LLC 
+(1,342 
+) 
+(1,076 
+) 
+— 
+Cumulative effect of change in accounting principle 
+— 
+— 
+(181 
+) 
+Non-cash derivative expense 
+1,635 
+(135 
+) 
+487 
+Deferred income tax expense (benefit) 
+13,209 
+(6,697 
+) 
+8,432 
+Non-cash charge related to compensation plans 
+1,906 
+1,225 
+858 
+Changes in current assets and liabilities: 
+Accounts receivable, trade 
+(11,169 
+) 
+(4,495 
+) 
+(1,438 
+) 
+Other current assets 
+670 
+971 
+(2,667 
+) 
+Current liabilities 
+(8,666 
+) 
+2,903 
+5,185 
+Change in gas balancing receivable 
+322 
+376 
+(340 
+) 
+Change in gas balancing payable 
+(289 
+) 
+400 
+(491 
+) 
+Change in other long-term liabilities 
+(18 
+) 
+(20 
+) 
+(15 
+) 
+Change in other assets, net 
+(292 
+) 
+(448 
+) 
+(349 
+) 
+Cash provided by operating activities 
+74,010 
+70,908 
+34,629 
+Cash flows from investing activities: 
+Capital expenditures 
+(73,072 
+) 
+(64,649 
+) 
+(50,705 
+) 
+Distribution from Medusa Spar, LLC 
+463 
+339 
+24,908 
+Proceeds from sale of pipeline and other facilities 
+— 
+— 
+1,500 
+Proceeds from sale of mineral interests 
+— 
+— 
+982 
+Cash used by investing activities 
+(72,609 
+) 
+(64,310 
+) 
+(23,315 
+) 
+Cash flows from financing activities: 
+Change in accrued liabilities to be refinanced 
+5,000 
+— 
+(3,861 
+) 
+Increase in debt 
+7,000 
+90,000 
+198,000 
+Payments on debt 
+(12,000 
+) 
+(205,915 
+) 
+(133,000 
+) 
+Restricted cash 
+— 
+63,345 
+(63,345 
+) 
+Debt issuance cost 
+— 
+(984 
+) 
+(3,745 
+) 
+Issuance of common stock 
+2 
+44,047 
+— 
+Buyout of preferred stock 
+(637 
+) 
+— 
+— 
+Equity issued related to employee stock plans 
+(573 
+) 
+199 
+127 
+Capital leases 
+(576 
+) 
+(1,452 
+) 
+(1,320 
+) 
+Cash dividends on preferred stock 
+(318 
+) 
+(1,272 
+) 
+(1,277 
+) 
+Cash used by financing activities 
+(2,102 
+) 
+(12,032 
+) 
+(8,421 
+) 
+Net increase (decrease) in cash and cash equivalents 
+(701 
+) 
+(5,434 
+) 
+2,893 
+Cash and short-term investments: 
+Balance, beginning of period 
+3,266 
+8,700 
+5,807 
+Balance, end of period 
+$ 
+2,565 
+$ 
+3,266 
+$ 
+8,700 
+The accompanying notes are an integral part of these financial statements.
+46
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+1. ORGANIZATION 
+General 
+Callon Petroleum Company (“the Company” or “Callon”) was organized under the laws of the state of
+Delaware in March 1994 to serve as the surviving entity in the consolidation and combination of
+several related entities (referred to herein collectively as the “Constituent Entities”). The
+combination of the businesses and properties of the Constituent Entities with the Company was
+completed on September 16, 1994 (“Consolidation”).
+As a result of the Consolidation, all of the businesses and properties of the Constituent Entities
+are owned (directly or indirectly) by the Company. Certain registration rights were granted to the
+stockholders of certain of the Constituent Entities. See Note 7.
+The Company and its predecessors have been engaged in the acquisition, development and exploration
+of crude oil and natural gas since 1950. The Company’s properties are geographically concentrated
+in Louisiana, Alabama and offshore Gulf of Mexico.
+2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 
+Principles of Consolidation and Reporting 
+The Consolidated Financial Statements include the accounts of the Company, and its subsidiary,
+Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries, namely Callon Offshore
+Production, Inc. and Mississippi Marketing, Inc. All intercompany accounts and transactions have
+been eliminated. Certain prior year amounts have been reclassified to conform to presentation in
+the current year.
+Use of Estimates 
+The preparation of financial statements in conformity with generally accepted accounting principles
+requires management to make estimates and assumptions that affect the reported amounts of assets
+and liabilities and disclosure of contingent assets and liabilities at the date of the financial
+statements and the reported amounts of revenues and expenses during the reporting period. Actual
+results could differ from those estimates.
+Asset Retirement Obligations 
+In June 2001, the FASB issued Statement of Financial Accounting Standards No. 143, “Accounting for
+Asset Retirement Obligations” (“SFAS 143”), effective for fiscal years beginning after June 15,
+2002. SFAS 143 essentially requires entities to record the fair value of a liability for
+obligations associated with the retirement of tangible long-lived assets and the associated asset
+retirement costs. Callon adopted SFAS 143 on January 1, 2003 resulting in a cumulative effect of
+accounting change of $181,000, net of tax. See Note 8.
+47
+Table of Contents 
+Oil and Gas Properties 
+The Company follows the full-cost method of accounting for oil and gas properties whereby all costs
+incurred in connection with the acquisition, exploration and development of oil and gas reserves,
+including certain overhead costs, are capitalized. Such amounts include the cost of drilling and
+equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest
+capitalized on unevaluated leases and other costs related to exploration and development
+activities. General and administrative costs capitalized include salaries and related fringe
+benefits paid to employees directly engaged in the acquisition, exploration and/or development of
+oil and gas properties as well as other directly identifiable general and administrative costs
+associated with such activities. Such capitalized costs ($7.1 million in 2005, $7.2 million in 2004
+and $8.4 million in 2003) do not include any costs related to production or general corporate
+overhead. Costs associated with unevaluated properties, including capitalized interest on such
+costs, are excluded from amortization. Unevaluated property costs are transferred to evaluated
+property costs at such time as wells are completed on the properties, the properties are sold or
+management determines that these costs have been impaired.
+Costs of properties, including future development and future site restoration, dismantlement and
+abandonment costs, which have proved reserves and properties which have been determined to be
+worthless, are depleted using the unit-of-production method based on proved reserves. If the total
+capitalized costs of oil and gas properties, net of accumulated amortization and deferred taxes
+relating to oil and gas properties, exceed the sum of (1) the estimated future net revenues from
+proved reserves at current prices discounted at 10% and (2) the lower of cost or market of
+unevaluated properties (the full-cost ceiling amount), net of tax effects, then such excess is
+charged to expense during the period in which the excess occurs. See Note 9.
+Upon the acquisition or discovery of oil and gas properties, management estimates the future net
+costs to be incurred to dismantle, abandon and restore the property using available geological,
+engineering and regulatory data. Such cost estimates are periodically updated for changes in
+conditions and requirements. Such estimated amounts are considered as part of the full-cost pool
+subject to amortization upon acquisition or discovery. Until January 1, 2003, such costs were
+capitalized as oil and gas properties as the actual restoration, dismantlement and abandonment
+activities took place. As discussed above under “Asset Retirement Obligations,” beginning January
+1, 2003, the Company changed the method for which we account for such costs upon adoption of SFAS
+143 and these costs are now capitalized to the full cost pool when the related liabilities are
+incurred in accordance with the provisions of SFAS 143. In accordance with the SEC issued Staff
+Accounting Bulleting No. 106, assets recorded in connection with the recognition of an asset
+retirement obligation pursuant to SFAS 143 are included as part of the costs subject to the
+full-cost ceiling limitation. The future cash outflows associated with settling the recorded asset
+retirement obligations are excluded from the computation of the present value of estimated future
+net revenues used in applying the ceiling test.
+Property and Equipment 
+Depreciation of other property and equipment is provided using the straight-line method over
+estimated lives of three to 20 years. Depreciation of pipeline and other facilities is provided
+using the straight-line method over estimated lives of 15 to 27 years. Depreciation expense of
+$227,000, $346,000 and $578,000 relating to other property and equipment was included in general
+and administrative expenses in the Company’s statements of operations for the years ended December
+31, 2005, 2004 and 2003, respectively. The accumulated depreciation on other property and
+equipment was $10.6 million and $10.4 million as of December 31, 2005 and 2004, respectively.
+48
+Table of Contents 
+Investment in Medusa Spar LLC 
+In December 2003, the Company announced the formation of a limited liability company, Medusa Spar
+LLC, which now owns a 75% undivided ownership interest in the deepwater spar production facilities
+on Callon’s Medusa Field in the Gulf of Mexico. The Company contributed a 15% undivided ownership
+interest in the production facility to Medusa Spar LLC in return for approximately $25 million in
+cash and a 10% ownership interest in the LLC. The LLC will earn a tariff based upon production
+volume throughput from the Medusa area. Callon is obligated to process our share of production from
+the Medusa Field and any future discoveries in the area through the spar production facilities.
+This arrangement allows Callon to defer the cost of the spar production facility over the life of
+the Medusa Field. The Company’s cash proceeds were used to reduce the balance outstanding under
+its senior secured credit facility. The LLC used the cash proceeds from $83.7 million of
+non-recourse financing and a cash contribution by one of the LLC owners to acquire its 75% interest
+in the spar. On December 31, 2005, $47.0 million of the financing was outstanding. The balance of
+Medusa Spar LLC is owned by Oceaneering International, Inc. (NYSE:OII) and Murphy Oil Corporation
+(NYSE:MUR). The Company is accounting for our 10% ownership interest in the LLC under the equity
+method.
+Natural Gas Imbalances 
+The Company follows the entitlement method of accounting for its proportionate share of gas
+production on a well-by-well basis, recording a receivable to the extent that a well is in an
+“undertake” position and conversely recording a liability to the extent that a well is in an
+“overtake” position. Gas balancing receivables were $403,000 and $725,000 as of December 31, 2005
+and 2004, respectively. Gas balancing payables were $304,000 and $594,000 as of December 31, 2005
+and 2004, respectively.
+Derivatives 
+The Company uses derivative financial instruments for price protection purposes on a limited amount
+of its future production and does not use them for trading purposes. Such derivatives are
+accounted for under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative
+Instruments and Hedging Activities” (“SFAS 133”) as amended. See Note 6.
+Income Tax 
+The Company follows the asset and liability method of accounting for deferred income taxes
+prescribed by Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”
+(“SFAS 109”). The statement provides for the recognition of a deferred tax asset for deductible
+temporary timing differences, capital and operating loss carryforwards, statutory depletion
+carryforward and tax credit carryforwards, net of a valuation allowance. The valuation allowance
+is provided for that portion of the asset for which it is deemed more likely than not will not be
+realized. See Note 3.
+Accounts Receivable 
+Accounts receivable consists primarily of accrued oil and gas production receivables. The balance
+in the reserve for doubtful accounts included in accounts receivable was $66,000 and $103,000 at
+December 31, 2005 and 2004, respectively. Net charge offs recorded against the reserve for
+doubtful accounts were $37,000 in 2005 and zero in 2004. There were no provisions to expense in
+the three-year period ended December 31, 2005.
+49
+Table of Contents 
+Accrued Liabilities to be Refinanced 
+Amounts included in accrued liabilities to be refinanced represent capital
+expenditures that were refinanced with the availability
+under the Company’s senior secured credit facility subsequent to the end of the year.
+Major Customers 
+The Company’s production is sold generally on month-to-month contracts at prevailing prices. The
+following table identifies customers to whom it sold a significant percentage of its total oil and
+gas production during each of the years ended:
+December 31, 
+2005 
+2004 
+2003 
+Shell Trading Company 
+34 
+% 
+30 
+% 
+— 
+Louis Dreyfus Energy Services 
+16 
+% 
+23 
+% 
+27 
+% 
+Plains Marketing, L.P. 
+16 
+% 
+13 
+% 
+— 
+Chevron Texaco Natural Gas 
+10 
+% 
+6 
+% 
+— 
+Reliant Energy Services 
+— 
+6 
+% 
+28 
+% 
+Prior Energy Corporation 
+— 
+— 
+20 
+% 
+Because alternative purchasers of oil and gas are readily available, the Company believes that the
+loss of any of these purchasers would not result in a material adverse effect on its ability to
+market future oil and gas production.
+Statements of Cash Flows 
+For purposes of the Consolidated Financial Statements, the Company considers all highly liquid
+investments purchased with an original maturity of three months or less to be cash equivalents.
+The Company paid no federal income taxes for the three years in the period ended December 31, 2005.
+During the years ended December 31, 2005, 2004 and 2003, the Company made cash payments for
+interest of $19,854,000, $23,197,000 and $27,913,000, respectively.
+Accounting Pronouncements 
+On December 16, 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of
+Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”), which
+is a revision of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based
+Compensation” (“SFAS 123”). SFAS 123R supersedes APB Opinion No. 25, Accounting for Stock Issued
+to Employees”, and amends Statement of Financial Accounting Standards No. 95, “Statement of Cash
+Flows.” Generally, the approach in SFAS 123R is similar to the approach described in SFAS 123.
+However, SFAS 123R requires all share-based payments to employees, including grants of employee
+stock options, to be recognized in the income statement based on their fair values. Pro forma
+disclosure is no longer an alternative.
+In April 2005, the Securities and Exchange Commission (“SEC”) delayed the effective date of SFAS
+123R for public companies to no later than the beginning of the first fiscal year beginning after
+June 15, 2005. Early adoption is permitted in periods in which financial statements have not yet
+been issued. SFAS 123R permits public companies to adopt its requirements using one of two methods
+below:
+50
+Table of Contents 
+• 
+A “modified prospective” method in which compensation cost is recognized beginning with
+the effective date (a) based on the requirements of SFAS 123R for all share-based payments
+granted after the effective date and (b) based on the requirements of SFAS 123 for all
+awards granted to employees prior to the effective date of SFAS 123R that remain unvested
+on the effective date; or 
+• 
+A “modified retrospective” method which includes the requirements of the modified
+prospective method described above, but also permits entities to restate based on the
+amounts previously recognized under SFAS 123 for purposes of pro forma disclosures either
+(a) all prior periods presented or (b) prior interim periods of the year of adoption. 
+As permitted by SFAS 123, through December 31, 2005, the Company accounted for share-based payments
+to employees using APB Opinion 25’s intrinsic value method and, as such, generally recognized no
+compensation cost for employee stock options. Accordingly, the adoption of SFAS 123R’s fair value
+method could have a significant impact on our result of operations, although it will have no impact
+on our overall financial position. The impact of SFAS 123R cannot be predicted at this time
+because it will depend on levels of share-based payments granted in the future. However, had we
+adopted SFAS 123R in prior periods, the impact of that standard would have approximated the impact
+of SFAS 123 as described in the disclosure of pro forma net income and earnings per share below
+under “Stock-Based Compensation.” The Company adopted SFAS 123R on January 1, 2006 using the
+modified prospective method.
+Stock-Based Compensation 
+The Company’s pro forma net income (loss) and net income (loss) per share of common stock for the
+years ended December 31, 2005, 2004 and 2003 had compensation costs been recorded using the fair
+value method in accordance with SFAS 123, as amended by Statement of Financial Accounting Standards
+No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure-an amendment of SFAS
+No. 123 (“SFAS 148”), are presented below pursuant to the disclosure requirements of SFAS 148 (in
+thousands except per share data):
+2005 
+2004 
+2003 
+(In thousands, except per share data) 
+Net income (loss) available to common shares,
+as reported 
+$ 
+26,458 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+Stock-based compensation expense included
+in net income as reported, net of tax 
+1,313 
+348 
+17 
+Deduct: Total stock-based
+compensation expense under fair
+value based method, net of tax 
+(1,497 
+) 
+(549 
+) 
+(247 
+) 
+Pro forma net income (loss) available to
+common shares 
+$ 
+26,274 
+$ 
+20,028 
+$ 
+(19,498 
+) 
+Basic
+earnings (loss) per share: As Reported 
+1.43 
+1.28 
+(1.41 
+) 
+Pro Forma 
+1.42 
+1.27 
+(1.43 
+) 
+Diluted earnings (loss) per share: As Reported 
+1.28 
+1.22 
+(1.41 
+) 
+Pro Forma 
+1.27 
+1.20 
+(1.43 
+) 
+See Note 11 for descriptions and additional disclosures related to the stock incentive plans.
+51
+Table of Contents 
+Per Share Amounts 
+Basic income or loss per common share was computed by dividing net income or loss by the weighted
+average number of shares of common stock outstanding during the year. Diluted income or loss per
+common share was determined on a weighted average basis using common shares issued and outstanding
+adjusted for the effect of stock options considered common stock equivalents computed using the
+treasury stock method and the effect of the convertible preferred stock (if dilutive). The
+conversion of the preferred stock was not included in the annual calculation for 2003 due to its
+antidilutive effect on diluted income or loss per common share. In addition, below are the shares
+relating to stock options, warrants and restricted stock that were not included in diluted shares
+for the year ended December 31, 2003 due to the fact that the Company had a loss for this period.
+The Company had net income for the years ended December 31, 2005 and 2004 and all such shares were
+included as described below.
+Twelve Months Ended December 31, 
+(in thousands) 
+2003 
+Stock options 
+63 
+Warrants 
+424 
+Restricted Stock 
+248 
+A reconciliation of the basic and diluted per share computation is as follows (in thousands, except
+per share amounts):
+2005 
+2004 
+2003 
+(a) Net income (loss) available to common shares 
+$ 
+26,458 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+Preferred dividends assuming conversion of
+preferred stock(if dilutive) 
+318 
+1,272 
+— 
+(b) Income
+(loss) available to common shares assuming conversion of
+preferred stock (if dilutive) 
+$ 
+26,776 
+$ 
+21,501 
+$ 
+(19,268 
+) 
+(c) Weighted average shares outstanding 
+18,453 
+15,796 
+13,662 
+Dilutive impact of stock options 
+348 
+233 
+— 
+Dilutive impact of restricted stock 
+69 
+75 
+— 
+Dilutive impact of warrants 
+1,375 
+894 
+— 
+Convertible preferred stock (if dilutive) 
+638 
+680 
+— 
+(d) Total diluted shares 
+20,883 
+17,678 
+13,662 
+Stock options and warrants excluded due to the
+exercise price being greater than the stock price 
+1 
+89 
+2,297 
+Basic income (loss) per share (a ¸ c) 
+$ 
+1.43 
+$ 
+1.28 
+$ 
+(1.41 
+) 
+Diluted income (loss) per share (b ¸ d) 
+$ 
+1.28 
+$ 
+1.22 
+$ 
+(1.41 
+) 
+52
+Table of Contents 
+Fair Value of Financial Instruments 
+Fair value of cash, cash equivalents, accounts receivable, accounts payable, the capital lease and
+the senior secured credit facility approximates book value at December 31, 2005 and 2004. Fair
+value of long-term debt (specifically, the 9.75% Senior Notes) had an estimated fair value of 103%
+of face value at December 31, 2005.
+3. INCOME TAXES 
+The Company had a net current asset of $26.8 million and a net long-term liability of $31.6 million
+resulting in a net deferred tax liability of $4.8 million at December 31, 2005. At December 31,
+2004, the Company had a net current asset of $5.7 million and a net long-term asset of $3.0 million
+resulting in a net deferred tax asset of $8.7 million. Below is an analysis of the net deferred
+tax asset (liability) as of December 31, 2005 and 2004.
+December 31, 
+2005 
+2004 
+(In thousands) 
+Deferred Tax Asset: 
+Federal net operating loss carryforwards 
+$ 
+58,240 
+$ 
+56,271 
+Statutory depletion carryforward 
+4,443 
+4,124 
+Alternative minimum tax credit carryforward 
+547 
+326 
+SFAS 143-Asset Retirement Obligations 
+11,307 
+11,544 
+Other 
+1,389 
+2,786 
+Total deferred tax asset 
+75,926 
+75,051 
+Deferred Tax Liability: 
+Difference between book and tax basis for property 
+(80,565 
+) 
+(66,277 
+) 
+Other 
+(224 
+) 
+(112 
+) 
+Total deferred tax liability 
+(80,789 
+) 
+(66,389 
+) 
+Net deferred tax asset (liability) 
+$ 
+(4,863 
+) 
+$ 
+8,662 
+If not utilized, the Company’s federal net operating loss carryforwards will expire in 2013 through
+2020. The Company has significant state net operating loss carryforwards that are not included in
+the deferred tax asset above, as the Company does not anticipate generating taxable state income in
+the states in which these loss carryforwards apply. The Company has very limited state taxable
+income as primarily all of its revenue is generated in federal waters not subject to state income
+taxes.
+SFAS 109 provides for the weighing of positive and negative evidence in determining whether it is
+more likely than not that a deferred tax asset is recoverable. The Company achieved profitable
+operations in 2005 and 2004 and had income on an aggregate basis for the three-year period ended
+December 31, 2005. In addition, we expect 2006 production levels to meet or exceed 2005 levels. As
+a result, the Company has not provided a valuation allowance as of December 31, 2005.
+53
+Table of Contents 
+The Company incurred losses in 2002 and 2003 and had losses on an aggregate basis for the
+three-year period ended December 31, 2003. Because of these cumulative losses the Company
+established a full valuation allowance of $11.5 million as of December 31, 2003. For the
+three-year period ended December 31, 2004, the Company had income on an aggregate basis resulting
+from the Company achieving profitable operations in 2004 due to the Company’s first two deepwater
+projects starting in November 2003 and the refinancing of the Company’s highest cost debt. As a
+result, the Company reversed the valuation allowance, which had a balance of $7.0 million, as of
+December 31, 2004.
+Below is a reconciliation of the reported amount of income tax expense attributable to continuing
+operations for the year to the amount of income tax expense that would result from applying
+domestic federal statutory tax rates to pretax income from continuing operations.
+Year Ended December 31, 
+2005 
+2004 
+2003 
+Income tax expense (benefit) computed at
+the statutory federal income tax rate 
+35 
+% 
+35 
+% 
+(35 
+%) 
+Change in valuation allowance 
+— 
+(84 
+)% 
+118 
+% 
+Other 
+(1 
+%) 
+— 
+4 
+% 
+Effective income tax rate 
+34 
+% 
+(49 
+)% 
+87 
+% 
+4. OTHER COMPREHENSIVE INCOME 
+The Company’s other comprehensive income (loss) of $1.6 million, $(1.9 million) and $449,000 for
+the years ended December 31, 2005, 2004 and 2003 respectively, relates to the change in fair value
+of its derivatives (other comprehensive income (loss) was net of tax of $835,000, $1.0 million and
+$242,000 for the years ended December 31, 2005, 2004 and 2003, respectively). See Note 6.
+54
+Table of Contents 
+5. LONG-TERM DEBT 
+Long-term debt consisted of the following at:
+December 31, 
+2005 
+2004 
+(In thousands) 
+Senior Secured Credit Facility 
+$ 
+— 
+$ 
+5,000 
+9.75% Senior Notes (due 2010)
+net of discount 
+187,941 
+186,216 
+Capital Lease 
+1,135 
+1,711 
+Total Long-term Debt 
+189,076 
+192,927 
+Less current portion 
+263 
+576 
+Long-term portion 
+$ 
+188,813 
+$ 
+192,351 
+Senior Secured Credit Facility . On June 15, 2004, the Company closed on a three-year senior secured
+credit facility underwritten by Union Bank of California, N.A. (“Union Bank”) to replace the
+Company’s credit facility with Wachovia Bank, National Association (“Wachovia Bank”) which was
+expiring June 30, 2004. The credit facility had an initial borrowing base of $60 million, which was
+increased to $70 million in the second quarter of 2005. The borrowing base is reviewed and
+redetermined semi-annually and can be increased to a maximum of $175 million. Borrowings under the
+credit facility are secured by mortgages covering the Company’s five largest fields. The credit
+facility bears interest at 0.25% above a defined base rate depending on utilization of the
+borrowing base or, at the option of the Company, LIBOR plus 1.5% to 2.25% based on utilization of
+the borrowing base. Under the senior secured credit facility, a commitment fee of 0.25% or 0.375%
+per annum, depending on the amount of the unused portion of the borrowing base, is payable
+quarterly.
+The range of interest rates on the senior secured credit facility was 4.16% to 6.00% for the year
+ended December 31, 2005. The weighted average interest rate for the debt outstanding under the
+senior secured credit facility at December 31, 2004 was 4.16%. As of December 31, 2005 there were
+no borrowings outstanding under the facility; however, Callon had an aggregate of $7.5 million in
+outstanding letters of credit issued under the credit facility. These letters of credit secure
+obligations under the outstanding hedging contracts described in Note 6. The outstanding letters
+of credit reduce the amount available for borrowings under the credit facility. As a result, $62.5
+million was available for future borrowings under the credit facility as of December 31, 2005.
+Certain of the Company’s subsidiaries guarantee the Company’s obligations under the $200 million
+9.75% Senior Notes due 2010. The subsidiary guarantors are 100% owned, all of the guarantees are
+full and unconditional and joint and several, the parent company has no independent assets or
+operations and any subsidiaries of the parent company other than the subsidiary guarantors are
+minor.
+55
+Table of Contents 
+Restructured Debt . In December 2003 and in the first half of 2004, the Company completed several
+transactions which restructured all debt that was maturing through 2005. A summary of these
+transactions is as follows:
+• 
+borrowing $185 million pursuant to a senior unsecured credit facility for a term of
+seven years at an interest rate of 9.75% in December 2003; 
+• 
+the formation of Medusa Spar LLC in which the Company contributed its 15% ownership in
+the deepwater spar production facilities in return for a 10% interest in Medusa Spar LLC
+and approximately $25 million in cash; 
+• 
+borrowing an additional $15 million for a term of seven years at an interest rate of
+9.75% pursuant to a senior unsecured credit agreement in the first quarter of 2004; 
+• 
+closing a three-year senior secured credit facility with an initial borrowing base of
+$60 million in June 2004 which can be increased by the lender to $175 million; and 
+• 
+closing the public offering of 3,450,000 shares of common stock priced at $13.25 per
+share raising net proceeds of approximately $44 million, after expenses, in June 2004. 
+Below is a list of the debt which was extinguished and restructured with the funds raised from the
+transactions above.
+• 
+the Company’s $22.9 million, 10.125% senior subordinated notes due in 2004 
+• 
+the Company’s $40 million, 10.25% senior subordinated notes due in 2004 
+• 
+the Company’s $95 million, 12% senior unsecured credit facility due in 2005 
+• 
+the Company’s $33 million, 11% senior subordinated notes due in 2005 
+All of the above debt was extinguished before maturity which resulted in a loss on early
+extinguishment of debt for the years ended December 31, 2004 and 2003 of $3.0 million and $5.6
+million, respectively. In addition to restructuring the Company’s debt, Callon reduced the balance
+outstanding on its senior secured credit facility.
+9.75% Senior Notes (due 2010). In December 2003 the Company borrowed $185 million pursuant to a
+senior unsecured credit facility. The loans under the credit facility have a stated interest rate
+of 9.75% and a seven-year maturity. The net proceeds of $181.3 million were used to redeem $22.9
+million of 10.125% senior subordinated notes due July 31, 2004, $40 million of 10.25% senior
+subordinated notes due September 15, 2004 and $85 million of our 12% senior loans due March 31,
+2005 plus a 1% pre-payment premium of $850,000, and to reduce the balance outstanding under the
+Company’s senior secured credit facility. In conjunction with the new senior unsecured notes, the
+Company issued detachable warrants to purchase 2.775 million shares of it’s common stock at an
+exercise price of $10 per share and an expiration date of December 2010. The warrants were valued
+at $10.6 million and were treated as a discount on the debt. This senior unsecured debt matures
+December 8, 2010 and has an effective interest rate of 11.4%. The Company recorded the issuance of
+these new securities at a fair value of $171 million. Deferred costs of $14 million associated
+with the notes will be amortized over the life of the notes.
+During March 2004, Callon borrowed an additional $15 million under its 9.75% senior unsecured
+credit facility bringing the total outstanding under the facility to $200 million. The net proceeds
+of approximately $14 million were primarily used to retire the remaining $10 million of 12% senior
+loans due March 31, 2005 plus a 1% call premium of $100,000. The Company recorded the issuance of
+these additional new securities at a fair value of $14 million. Deferred costs of $1 million
+associated with the notes will be amortized over the life of the notes.
+56
+Table of Contents 
+In March 2004, the $200 million in aggregate principal amount of loans outstanding under the 9.75%
+senior unsecured credit facility were exchanged for 9.75% Senior Notes due 2010, Series A, “Series
+A notes”, issued pursuant to a senior indenture between Callon and American Stock Transfer & Trust
+Company dated March 15, 2004. On August 12, 2004, the Company completed an offer to exchange its
+9.75% Senior Notes due 2010, Series B, that have been registered under the Securities Act of 1933,
+for all outstanding Series A notes.
+In December 2005, 79,500 of the detachable warrants issued with the 9.75% Senior Notes due 2010
+were exercised. In addition, 265,210 of $0.01 warrants associated with the 12% senior unsecured
+credit facility due in 2005 were outstanding as of December 31, 2005.
+Capital Lease . In December 2001, the Company entered into a 10-year gas processing agreement
+associated with a production facility on Callon’s Mobile Block 952 Field with Hanover Compression
+Limited Partnership, which is being accounted for as a capital lease. Total minimum obligations
+are $8.4 million with interest representing approximately $2.8 million and the present value
+minimum obligations representing $5.6 million.
+Restrictive Covenants . The Indenture governing our 9.75% senior notes due 2010 and our senior
+secured credit facility contains various covenants including restrictions on additional
+indebtedness and payment of cash dividends. In addition, our senior secured credit facility
+contains covenants for maintenance of certain financial ratios. The Company was in compliance with
+these covenants at December 31, 2005.
+Future minimum lease payments and debt maturities (in thousands) are as follows:
+Capital Lease 
+Year 
+Payments 
+Debt 
+2006 
+$ 
+439 
+$ 
+— 
+2007 
+348 
+— 
+2008 
+228 
+— 
+2009 
+229 
+— 
+2010 
+220 
+200,000 
+Thereafter 
+245 
+— 
+57
+Table of Contents 
+6. DERIVATIVES 
+The Company periodically uses derivative financial instruments to manage oil and gas price risk.
+Settlements of gains and losses on commodity price contracts are generally based upon the
+difference between the contract price or prices specified in the derivative instrument and a NYMEX
+price or other cash or futures index price.
+The Company’s derivative contracts that are accounted for as cash flow hedges under SFAS 133 are
+recorded at fair market value and the changes in fair value are recorded through other
+comprehensive income (loss), net of tax, in stockholders’ equity. The cash settlements on these
+contracts are recorded as an increase or decrease in oil and gas sales. The changes in fair value
+related to ineffective derivative contracts are recognized as derivative expense (income). The
+cash settlement on these contracts is also recorded within derivative expense (income). The
+changes in fair value of the Company’s derivative contracts that are not designated as effective
+cash flow hedges are recorded through the statement of operations as derivative expense (income).
+Cash settlements on effective cash flow hedges for the years ended December 31, 2005, 2004 and 2003
+resulted in a reduction of oil and gas sales in the amount of $10.3 million, $13.8 million and $2.9
+million, respectively. Cash settlements on ineffective derivative contracts were recorded as
+derivative expense in the amount of $4.4 million and $1.2 million for the years ended December 31,
+2005 and 2004, respectively. These contracts were deemed ineffective as a result of a shortfall in
+production volumes due to downtime from the tropical storm activity in the third quarters of 2005
+and 2004 impacting third and fourth quarter production volumes for the respective years.
+The following table summarizes derivative expense for the periods presented (in thousands):
+December 31, 
+2005 
+2004 
+2003 
+Amortization of derivative contract premiums 
+$ 
+1,634 
+$ 
+— 
+$ 
+— 
+Change in fair value and settlements of ineffective
+derivative contracts 
+4,394 
+1,209 
+— 
+Change in fair value and settlements of
+non-designated
+derivative contracts 
+— 
+162 
+535 
+$ 
+6,028 
+$ 
+1,371 
+$ 
+535 
+58
+Table of Contents 
+The Company had a current liability of $1.2 million and a current asset of $889,000 relating to the
+fair value of its respective derivative contracts as of December 31, 2005.
+Listed in the table below are the outstanding derivative contracts as of December 31, 2005:
+Swaps 
+Volumes per 
+Quantity 
+Average 
+Product 
+Month 
+Type 
+Price 
+Period 
+Oil 
+15,000 
+Bbls 
+$ 
+55.00 
+01/06-06/06 
+Collars 
+Average 
+Average 
+Volumes per 
+Quantity 
+Floor 
+Ceiling 
+Product 
+Month 
+Type 
+Price 
+Price 
+Period 
+Oil 
+30,000 
+Bbls 
+$ 
+60.00 
+$ 
+77.10 
+01/06-12/06 
+Natural Gas 
+200,000 
+MMBtu 
+$ 
+10.00 
+$ 
+16.00 
+01/06-03/06 
+Natural Gas 
+100,000 
+MMBtu 
+$ 
+8.33 
+$ 
+11.93 
+01/06-09/06 
+7. COMMITMENTS AND CONTINGENCIES 
+From time to time, the Company, as part of the Consolidation and other capital transactions,
+entered into registration rights agreements whereby certain parties to the transactions are
+entitled to require the Company to register common stock of the Company owned by them with the
+Securities and Exchange Commission for sale to the public in firm commitment public offerings and
+generally to include shares owned by them, at no cost, in registration statements filed by the
+Company. Costs of the offering will not include broker’s discounts and commissions, which will be
+paid by the respective sellers of the common stock.
+The Company is involved in various claims and lawsuits incidental to its business. In the opinion
+of management, the ultimate liability thereunder, if any, will not have a material adverse effect
+on the financial position or results of operations of the Company.
+The Company’s Medusa deepwater property is eligible for royalty suspensions pursuant to the Deep
+Water Royalty Relief Act. In addition, the Company has several shallow water, deep natural gas
+properties and prospects that are eligible for royalty suspensions. However, the federal offshore
+leases covering these properties contain “price threshold” provisions for oil and gas prices.
+Under these “price threshold” provisions, if the average monthly New York Mercantile Exchange
+(NYMEX) sales price for oil or gas during a fiscal year exceeds the price threshold for oil or gas,
+respectively, then royalties on the associated production must be paid to the Minerals Management
+Service (MMS) at the rate stipulated in the lease. The price thresholds are adjusted annually by
+the implicit price deflator for the GDP. The determination of whether or not royalties are due as
+a result of the average NYMEX price exceeding the price threshold is made during the first quarter
+of the succeeding year. Any royalty payments due must be made shortly after this determination is
+made. If a royalty payment is due for all production during a year as a result of exceeding the
+price threshold, the lessee is required to make monthly royalty payments during the succeeding
+fiscal year for the succeeding year’s production. If at the end of any year the average NYMEX
+price is below the price threshold, the lessee can apply for a refund for any associated royalties
+paid during that year and the lessee will not be required to pay royalties monthly during the
+succeeding year for the succeeding year’s production.
+59
+Table of Contents 
+The thresholds and actual average NYMEX for 2005 are in the table below.
+2005 
+Actual Average 
+Threshold 
+NYMEX 
+Deepwater Oil Prices ($/bbl) 
+34.73 
+56.57 
+Deepwater Natural Gas Prices ($/mmbtu) 
+4.34 
+8.96 
+Shallow Water, Deep Natural Gas
+Prices ($/mmbtu) 
+9.60 
+8.96 
+The Company was required to make monthly royalty payments for 2005 deepwater oil and gas production
+and will be required to make monthly royalty payments for 2006. With regard to the shallow water,
+deep natural gas royalty relief, the Company will not be required to make monthly royalty payments
+for 2006.
+In the year succeeding the year in which any of the Company’s properties became subject to
+royalties as the result of the average NYMEX price exceeding the price threshold, the portion of
+reserves attributable to potential future royalties would not be included in a year-end reserve
+report. However, if the average NYMEX prices were below the price thresholds in subsequent years,
+our reserves would be increased to reflect reserves previously attributed to future royalties. As
+a result, reported oil and gas reserves could materially increase or decrease, depending on the
+relation of price thresholds versus the average NYMEX prices. The reduction in revenues resulting
+from an obligation to pay these royalties and subsequent reduction of proved reserves could have a
+material adverse effect on the Company’s results of operations and financial condition. The
+Company’s reserve report as of December 31, 2005 excluded oil and gas reserves for Medusa that are
+subject to MMS royalties as a result of the average 2005 NYMEX prices for oil and gas exceeding the
+price thresholds.
+The Company’s activities are subject to federal, state and local laws and regulations governing
+environmental quality and pollution control. Although no assurances can be made, the Company
+believes that, absent the occurrence of an extraordinary event, compliance with existing federal,
+state and local laws, rules and regulating the release of materials in the environment or otherwise
+relating to the protection of the environment will not have a material effect upon the capital
+expenditures, earnings or the competitive position of the Company with respect to its existing
+assets and operations. The Company cannot predict what effect additional regulation or
+legislation, enforcement polices thereunder, and claims for damages to property, employees, other
+persons and the environment resulting from the Company’s operations could have on its activities.
+8. ASSET RETIREMENT OBLIGATIONS 
+As discussed in Note 2, the Company adopted SFAS 143 on January 1, 2003. The impact of adopting
+the statement resulted in a gain of $181,000, net of tax, which was reported as a cumulative effect
+of change in accounting principle.
+Approximately $30.3 million was recorded as the present value of asset retirement obligations on
+January 1, 2003 with the adoption of SFAS 143 related to the Company’s oil and gas properties.
+Interest is accreted on this amount and reported as accretion expense in the Consolidated
+Statements of Operations.
+60
+Table of Contents 
+Assets, primarily short-term U.S. Government securities, of approximately $6.0 million at December
+31, 2005, of which $4.1 million was current, was recorded as restricted investments. These assets
+are held in abandonment trusts (“Trusts”) dedicated to pay future abandonment costs of oil and gas
+properties in which the Company has sold a net profit interest (“NPI”). In September 2005, Callon
+purchased the NPI’s
+which included the Trusts. See Note 10 to the Consolidated Financial Statements for more detail on
+the NPI transaction.
+The following table summarizes the activity for the Company’s asset retirement obligations:
+Twelve Months Ended 
+December 31, 2005 
+December 31, 2004 
+Asset retirement obligations at
+beginning of period 
+$ 
+38,282 
+$ 
+33,691 
+Accretion expense 
+3,549 
+3,400 
+Net profits interest accretion 
+331 
+459 
+Liabilities incurred 
+2,365 
+3,065 
+Liabilities settled 
+(5,184 
+) 
+(2,076 
+) 
+Revisions to estimate 
+(1,070 
+) 
+(257 
+) 
+Asset retirement obligation at end of period 
+38,273 
+38,282 
+Less: current retirement obligations 
+(21,660 
+) 
+(13,300 
+) 
+Long-term retirement obligations 
+$ 
+16,613 
+$ 
+24,982 
+61
+Table of Contents 
+9. OIL AND GAS PROPERTIES 
+The following table discloses certain financial data relating to the Company’s oil and gas
+activities, all of which are located in the United States.
+Years Ended December 31, 
+2005 
+2004 
+2003 
+(In thousands) 
+Capitalized costs incurred: 
+Evaluated Properties- 
+Beginning of period balance 
+$ 
+862,101 
+$ 
+802,912 
+$ 
+762,918 
+Property acquisition costs 
+6,627 
+1,355 
+1,154 
+Exploration costs 
+46,379 
+26,749 
+21,390 
+Development costs 
+26,481 
+32,004 
+33,972 
+SFAS 143-Asset Retirement Obligation 
+(3,890 
+) 
+(918 
+) 
+18,002 
+Medusa Spar transaction 
+— 
+— 
+(33,542 
+) 
+Sale of mineral interests 
+— 
+(1 
+) 
+(982 
+) 
+End of period balance 
+$ 
+937,698 
+$ 
+862,101 
+$ 
+802,912 
+Unevaluated Properties (excluded from
+amortization) - 
+Beginning of period balance 
+$ 
+39,042 
+$ 
+34,251 
+$ 
+40,997 
+Additions 
+18,739 
+16,367 
+5,228 
+Capitalized interest 
+5,655 
+4,577 
+4,862 
+Transfers to evaluated 
+(14,371 
+) 
+(16,153 
+) 
+(16,836 
+) 
+End of period balance 
+$ 
+49,065 
+$ 
+39,042 
+$ 
+34,251 
+Accumulated depreciation, depletion
+and amortization- 
+Beginning of period balance 
+$ 
+494,453 
+$ 
+447,000 
+$ 
+426,254 
+Provision charged to expense 
+44,946 
+47,453 
+28,195 
+Cumulative effect of change in accounting
+Principle 
+— 
+— 
+(7,449 
+) 
+End of period balance 
+$ 
+539,399 
+$ 
+494,453 
+$ 
+447,000 
+Unevaluated property costs, primarily lease acquisition costs incurred at federal and state lease
+sales, unevaluated drilling costs, capitalized interest and general and administrative costs being
+excluded from the amortizable evaluated property base, consisted of $18.8 million incurred in 2005,
+$7.8 million incurred in 2004 and $22.5 million incurred in 2003 and prior. These costs are
+directly related to the acquisition and evaluation of unproved properties and major development
+projects. The excluded costs and related reserves are included in the amortization base as the
+properties are evaluated and proved reserves are established or impairment is determined. The
+Company expects that the majority of these costs will be evaluated over the next three to five-year
+period.
+Depletion per unit-of-production (thousand cubic feet of gas equivalent) amounted to $2.39, $2.18
+and $2.03 for the years ended December 31, 2005, 2004, and 2003, respectively.
+62
+Table of Contents 
+Under the full-cost accounting rules of the SEC, the Company reviews the carrying value of its
+proved oil and gas properties each quarter. Under these rules, capitalized costs of proved oil and
+gas properties net of accumulated depreciation, depletion and amortization (DD&A) and deferred
+income taxes, may not exceed the
+present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10
+percent, plus the lower of cost or fair value of unproved properties net of related tax effects.
+These rules generally require pricing future oil and gas production at the unescalated market price
+for oil and gas at the end of each fiscal quarter and require a write-down if the “ceiling” is
+exceeded, unless prices recover sufficiently subsequent to the balance sheet date before the
+release of the financial statements. Given the volatility of oil and gas prices, it is reasonably
+possible that the Company’s estimate of discounted future net cash flows from proved oil and gas
+reserves could change in the near term. If oil and gas prices decline significantly, even if only
+for a short period of time, it is possible that writedowns of oil and gas properties could occur in
+the future.
+10. NET PROFITS INTEREST 
+From 1989 through 1994, the Constituent Entities entered into separate agreements to purchase
+certain oil and gas properties with gross contract acquisition prices of $170,000,000 ($150,000,000
+net as of closing dates) and in simultaneous transactions, entered into agreements to sell
+overriding royalty interests (“ORRI”) in the acquired properties. These ORRI were in the form of
+NPI’s equal to a significant percentage of the excess of gross proceeds over costs, as defined by
+the agreements, from the acquired oil and gas properties. In September 2005, the Company purchased
+the NPI’s for $5 million before intervening operations. Included in the transaction were the
+Trusts which were established at the inception of the NPI’s for future plugging and abandonment
+liabilities.
+The Company, pursuant to the purchase agreements, created the Trusts (see Note 8) whereby funds are
+provided out of gross production proceeds from the properties for the estimated amount of future
+abandonment obligations related to the working interests owned by the Company. The Trusts are
+administered by unrelated third party trustees for the benefit of the Company’s working interest in
+each property. The Trust agreements limit disbursement of funds to the satisfaction of abandonment
+obligations. Any funds remaining in the Trusts after all restoration, dismantlement and
+abandonment obligations have been met will be distributed to Callon. Estimated future revenues and
+costs associated with the Trusts are also excluded from the oil and gas reserve disclosures at Note
+13. As of December 31, 2005 and 2004, the Trusts’ assets (all cash and investments) totaled $6.0
+million and $7.7 million respectively, all of which will be available to the Company to pay the
+restoration, dismantlement and abandonment costs. SFAS 143, discussed in Note 2 and 8, does not
+allow the Trusts’ assets to be used to offset the associated abandonment liability. The Company did
+not record any income or loss associated with the Trust asset or abandonment liability as a result
+of adoption of SFAS 143.
+63
+Table of Contents 
+11. EMPLOYEE BENEFIT PLANS 
+The Company has adopted a series of incentive compensation plans designed to align the interest of
+the executives and employees with those of its stockholders. The following is a brief description
+of each plan:
+Savings and Protection Plan 
+The Savings and Protection Plan (“401-K Plan”) provides employees with the
+option to defer receipt of a portion of their compensation and the Company may, at
+its discretion, match a portion of the employee’s deferral with cash and Company
+Common Stock. The Company may also elect, at its discretion, to contribute a
+non-matching amount in cash and Company Common Stock to employees. The amounts held
+under the 401-K Plan are invested in various funds maintained by a third party in
+accordance with the directions of each employee. An employee is fully vested,
+including Company discretionary contributions, immediately upon participation in the
+401-K Plan. The total amounts contributed by the Company, including the value of
+the common stock contributed, were $557,000, $528,000 and $562,000 in the years
+2005, 2004 and 2003, respectively.
+1994 Stock Incentive Plan 
+The 1994 Stock Incentive Plan (the “1994 Plan”), approved by the shareholders
+in 1994, provides for 600,000 shares of Common Stock to be reserved for issuance
+pursuant to such plan. Under the 1994 Plan, the Company may grant both stock
+options qualifying under Section 422 of the Internal Revenue Code and options that
+are not qualified as incentive stock options, as well as performance shares. These
+options have an expiration date of 10 years from the date of grant.
+1996 Stock Incentive Plan 
+On August 23, 1996, the Board of Directors of the Company approved and adopted
+the Callon Petroleum Company 1996 Stock Incentive Plan (the “1996 Plan”). The 1996
+Plan was approved by the shareholders in 1997 and provides for the same types of
+awards as the 1994 Plan and is limited to a maximum of 1,200,000 shares (as amended
+from the original 900,000 shares) of common stock that may be subject to outstanding
+awards. Unvested options are subject to forfeiture upon certain termination of
+employment events and expire 10 years from the date of grant.
+The Company granted 533,000 stock options to employees on March 23, 2000 and
+120,000 stock options to directors on July 25, 2000 at $10.50 per share. The March
+23, 2000 grant was subject to shareholder approval of an amendment to the 1996 Stock
+Incentive Plan. The amendment, which was approved on May 9, 2000 at the Annual
+Meeting of Shareholders, increased the number of shares reserved for issuance under
+the 1996 plan to 2,200,000 shares. The excess of the market price over the exercise
+price on the approval date of the amendment was amortized over the three-year
+vesting period of the options. Compensation costs of $27,000 were recognized in
+2003, related to these options.
+64
+Table of Contents 
+In 2004, the Company awarded 455,000 performance shares from the 1994 and 1996
+Plans. These shares vest to the recipients over a five-year period (one-fifth in
+each year) beginning in July 2005. The deferred compensation portion of this grant
+will be amortized to expense over the vesting period. The non-cash amortization
+expense in 2005 and 2004 was $1,029,000 and $532,000, respectively. In 2005, an additional non-cash expense of $989,000 was
+recognized for accelerated vesting of performance shares for an executive officer
+and two directors of the Company, two of whom are deceased, and the retirement of an
+employee.
+2002 Stock Incentive Plan 
+On February 14, 2002, the Board of Directors of the Company approved and adopted
+the 2002 Stock Incentive Plan (the “2002 Plan”). Pursuant to the 2002 Plan, 350,000
+shares of common stock shall be reserved for issuance upon the exercise of options or
+for grants of stock options, stock appreciation rights or units, bonus stock, or
+performance shares or units. This Plan qualified as a “broadly based” plan under the
+provisions of the New York Stock Exchange’s rules and regulations and therefore did
+not require shareholder approval. Because the 2002 Plan is a broadly based plan, the
+aggregate number of shares underlying awards granted to officers and directors cannot
+exceed 50% of the total number of shares underlying the awards granted to all
+employees during any three-year period.
+In 2002, the Company awarded 300,000 shares of restricted stock from the 1996 and the
+2002 Plan and 70,500 from treasury shares to be issued as vested. The issuance of
+the restricted stock using treasury shares did not require shareholder approval
+pursuant to the New York Stock Exchange’s rules and regulations, and therefore
+shareholder approval was not sought. These shares vested to the recipients over a
+three-year period (one-third in each year) beginning in November 2002. The deferred
+compensation portion of this grant was amortized to expense over the vesting period.
+The non-cash amortization expense in 2004 and 2003 was $374,000 and $454,000,
+respectively.
+Employee Stock Purchase Plan 
+In 1997, the Board of Directors authorized the implementation of the Callon Petroleum
+Company 1997 Employee Stock Purchase Plan (the “1997 ESPP”), which was approved by
+the Company’s shareholders at the 1997 Annual Meeting. The 1997 ESPP provided
+eligible employees of the Company with the opportunity to acquire a proprietary
+interest in the Company through participation in a payroll deduction-based employee
+stock purchase plan. An aggregate of 250,000 shares of common stock were reserved
+for issuance over the10-year term of the 1997 ESPP. The purchase price per share at
+which common stock was purchased on the participant’s behalf on each purchase date
+within an offering period was equal to 85 percent of the fair market value per share
+of common stock. As of December 31, 2004 there were no remaining shares available
+for purchase.
+65
+Table of Contents 
+A summary of the status of the Company’s stock option plans for the three most recent years and
+changes during the years then ended is presented in the table and narrative below:
+2005 
+2004 
+2003 
+Wtd Avg 
+Wtd Avg 
+Wtd Avg 
+Shares 
+Ex Price 
+Shares 
+Ex Price 
+Shares 
+Ex Price 
+Outstanding, beginning of year 
+1,512,599 
+$ 
+9.93 
+2,450,867 
+$ 
+9.84 
+2,520,417 
+$ 
+9.90 
+Granted (at market) 
+65,000 
+15.79 
+25,000 
+12.40 
+30,000 
+5.12 
+Exercised 
+(329,441 
+) 
+10.34 
+(437,918 
+) 
+9.74 
+(500 
+) 
+4.10 
+Forfeited 
+— 
+— 
+(525,350 
+) 
+9.80 
+(99,050 
+) 
+9.74 
+Expired 
+(42,600 
+) 
+10.60 
+— 
+— 
+— 
+— 
+Outstanding, end of year 
+1,205,558 
+$ 
+10.11 
+1,512,599 
+$ 
+9.93 
+2,450,867 
+$ 
+9.84 
+Exercisable, end of year 
+1,166,558 
+$ 
+9.88 
+1,446,486 
+$ 
+10.20 
+2,262,067 
+$ 
+10.31 
+Weighted average fair value of
+options granted (at market) 
+$ 
+5.93 
+$ 
+4.48 
+$ 
+2.97 
+The following table sets forth additional information regarding options outstanding at
+December 31, 2005. Contractual life and exercise prices represent weighted averages for options
+outstanding and options exercisable.
+Options Outstanding 
+Options Exercisable 
+Range of 
+Number 
+Contractual 
+Exercise 
+Number 
+Exercise 
+exercise prices 
+Outstanding 
+Life (years) 
+Price 
+Exercisable 
+Price 
+$3.70 to $6.41 
+185,308 
+6.6 
+$ 
+4.48 
+185,308 
+$ 
+4.48 
+$9.00 to $12.40 
+905,250 
+3.1 
+$ 
+10.64 
+905,250 
+$ 
+10.64 
+$13.56 to $19.72 
+115,000 
+6.4 
+$ 
+15.67 
+76,000 
+$ 
+14.11 
+The fair value of each option grant is estimated on the date of grant using the Black-Scholes
+option pricing model with the following weighted average assumptions used for options granted
+during the years presented are as follows:
+2005 
+2004 
+2003 
+Risk free interest rate 
+4.3 
+% 
+3.7 
+% 
+4.0 
+% 
+Expected life (years) 
+4.5 
+5.0 
+5.0 
+Expected volatility 
+37.5 
+% 
+45.1 
+% 
+65.3 
+% 
+Expected dividends 
+— 
+— 
+— 
+66
+Table of Contents 
+12. EQUITY TRANSACTIONS 
+On June 13, 2005, Callon called for redemption all of the Company’s outstanding shares of $2.125
+Convertible Exchange Preferred Stock, Series A. A notice of redemption and letter of transmittal
+was mailed to all holders of record as of the close of business on June 10, 2005. Between June 13,
+2005 and June 30, 2005, 180,173 shares of preferred stock were converted into 409,496 shares of the Company’s common stock.
+Subsequent to June 30, 2005, 392,935 shares of preferred stock were converted into 893,076 shares
+of the Company’s common stock. In addition, 23,563 shares of the Company’s preferred stock were
+redeemed for $606,000 on July 14, 2005. As a result of the redemption, we will benefit from an
+annual cash savings of $1.3 million in dividend payments.
+On June 22, 2004, we closed the public offering of three million shares of common stock priced at
+$13.25 per share raising net proceeds of approximately $38.2 million, after expenses. In addition,
+we granted the underwriter, Johnson Rice & Company L.L.C., an over-allotment option to purchase an
+additional 450,000 shares. On June 30, 2004, the underwriter exercised the over-allotment option
+for an additional 450,000 shares priced at $13.25 per share, raising the net proceeds of the
+offering by approximately $5.7 million, after expenses. The proceeds from the transactions were
+used to redeem $33 million of the 11% Senior Subordinated Notes due December 15, 2005 and for
+general corporate purposes.
+The Company adopted a stockholder rights plan on March 30, 2000, designed to assure that the
+Company’s stockholders receive fair and equal treatment in the event of any proposed takeover of
+the Company and to guard against partial tender offers, squeeze-outs, open market accumulations,
+and other abusive tactics to gain control without paying all stockholders a fair price. The rights
+plan was not adopted in response to any specific takeover proposal. Under the rights plan, the
+Company declared a dividend of one right (“Right”) on each share of the Company’s Common Stock.
+Each Right will entitle the holder to purchase one one-thousandth of a share of a Series B
+Preferred Stock, par value $0.01 per share, at an exercise price of $90 per one one-thousandth of a
+share.
+The Rights are not currently exercisable and will become exercisable only in the event a person or
+group acquires, or engages in a tender or exchange offer to acquire, beneficial ownership of 15
+percent or more (one existing stockholder was granted an exception for up to 21 percent) of the
+Company’s Common Stock. After the Rights become exercisable, each Right will also entitle its
+holder to purchase a number of common shares of the Company having a market value of twice the
+exercise price. The dividend distribution was made to stockholders of record at the close of
+business on April 10, 2000. The Rights will expire on March 30, 2010.
+13. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED) 
+The Company’s proved oil and gas reserves at December 31, 2005, 2004 and 2003 have been estimated
+by Huddleston & Co., Inc. who are the Company’s independent petroleum consultants. The reserves
+were prepared in accordance with guidelines established by the Securities and Exchange Commission
+(“SEC”). Accordingly, the following reserve estimates are based upon existing economic and
+operating conditions.
+There are numerous uncertainties inherent in establishing quantities of proved reserves. The
+following reserve data represents estimates only and should not be construed as being exact. In
+addition, the standardized measure of discounted future net cash flows should not be construed as
+the current market value of the Company’s oil and gas properties or the cost that would be incurred
+to obtain equivalent reserves. See Note 7 regarding the Deep Water Royalty Relief Act and the loss
+of reserves.
+67
+Table of Contents 
+Estimated Reserves 
+Changes in the estimated net quantities of crude oil and natural gas reserves, all of which are
+located onshore and offshore in the continental United States, are as follows:
+Reserve Quantities 
+Years Ended December 31, 
+2005 
+2004 
+2003 
+Proved developed and undeveloped reserves: 
+Crude Oil (MBbls): 
+Beginning of period 
+19,748 
+23,709 
+24,043 
+Revisions to previous estimates 
+316 
+(2,370 
+)(a) 
+(1 
+) 
+Purchase of reserves in place 
+71 
+— 
+— 
+Sales of reserves in place 
+— 
+— 
+(65 
+) 
+Extensions and discoveries 
+129 
+145 
+— 
+Production 
+(1,836 
+) 
+(1,736 
+) 
+(268 
+) 
+End of period 
+18,428 
+19,748 
+23,709 
+Natural Gas (MMcf): 
+Beginning of period 
+72,619 
+74,691 
+91,539 
+Revisions to previous estimates 
+(4,946 
+) 
+2,138 
+(6,407 
+)(a) 
+Purchase of reserves in place 
+1,308 
+— 
+— 
+Sales of reserves in place 
+— 
+— 
+(49 
+) 
+Extensions and discoveries 
+16,808 
+7,177 
+1,923 
+Production 
+(7,768 
+) 
+(11,387 
+) 
+(12,315 
+) 
+End of period 
+78,021 
+72,619 
+74,691 
+Proved developed reserves: 
+Crude Oil (MBbls): 
+Beginning of period 
+10,292 
+9,919 
+1,056 
+End of period 
+7,323 
+10,292 
+9,919 
+Natural Gas (MMcf): 
+Beginning of period 
+33,982 
+31,415 
+37,631 
+End of period 
+30,982 
+33,982 
+31,415 
+(a) 
+Includes Medusa royalty adjustment 
+68
+Table of Contents 
+Standardized Measure 
+The following tables present the Company’s standardized measure of discounted future net cash flows
+and changes therein relating to proved oil and gas reserves and were computed using reserve
+valuations based on regulations prescribed by the SEC. These regulations provide that the oil,
+condensate and gas price structure utilized to project future net cash flows reflects current
+prices (approximately $10.13 per Mcf for natural gas and $55.44 per Bbl for oil for the 2005
+disclosures, $6.51 per Mcf and $36.72 per Bbl for 2004
+disclosures, and $5.99 per Mcf and $30.50 per Bbl for 2003 disclosures) at each date presented and
+have not been escalated. Future production and development costs are based on current costs
+without escalation. The resulting net future cash flows have been discounted to their present
+values based on a 10% annual discount factor.
+Standardized Measure 
+Years Ended December 31, 
+2005 
+2004 
+2003 
+(In thousands) 
+Future cash inflows 
+$ 
+1,814,208 
+$ 
+1,198,096 
+$ 
+1,170,118 
+Future costs — 
+Production 
+(238,321 
+) 
+(231,616 
+) 
+(219,421 
+) 
+Development and net abandonment 
+(88,070 
+) 
+(74,335 
+) 
+(111,850 
+) 
+Future net inflows before income taxes 
+1,487,817 
+892,145 
+838,847 
+Future income taxes 
+(379,287 
+) 
+(166,284 
+) 
+(89,567 
+) 
+Future net cash flows 
+1,108,530 
+725,861 
+749,280 
+10% discount factor 
+(270,978 
+) 
+(209,968 
+) 
+(230,254 
+) 
+Standardized measure of discounted
+future net cash flows 
+$ 
+837,552 
+$ 
+515,893 
+$ 
+519,026 
+Changes in Standardized Measure 
+Years Ended December 31, 
+2005 
+2004 
+2003 
+(In thousands) 
+Standardized
+measure — beginning of period 
+$ 
+515,893 
+$ 
+519,026 
+$ 
+556,046 
+Sales and transfers, net of production costs 
+(116,913 
+) 
+(97,494 
+) 
+(62,396 
+) 
+Net change in sales and transfer prices,
+net of production costs 
+391,570 
+86,551 
+(41,011 
+) 
+Exchange and sale of in place reserves 
+— 
+— 
+(1,226 
+) 
+Purchases, extensions, discoveries, and
+improved
+recovery, net of future production and
+development costs incurred 
+127,848 
+77,576 
+25,632 
+Revisions of quantity estimates 
+(17,241 
+) 
+(41,314 
+) 
+(18,018 
+) 
+Accretion of discount 
+61,259 
+57,046 
+62,394 
+Net change in income taxes 
+(154,460 
+) 
+(45,262 
+) 
+16,460 
+Changes in production rates, timing and other 
+29,596 
+(40,236 
+) 
+(18,855 
+) 
+Standardized measure — end of period 
+$ 
+837,552 
+$ 
+515,893 
+$ 
+519,026 
+69
+Table of Contents 
+14. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) 
+First 
+Second 
+Third 
+Fourth 
+2005 
+Quarter 
+Quarter 
+Quarter(a) 
+Quarter(a) 
+(In thousands, except per share data) 
+Total revenues 
+$ 
+43,012 
+$ 
+41,668 
+$ 
+31,722 
+$ 
+24,888 
+Income from operations 
+18,134 
+17,696 
+8,692 
+9,783 
+Net income 
+9,475 
+9,311 
+3,683 
+4,307 
+Net income
+per common share — basic 
+$ 
+0.52 
+$ 
+0.52 
+$ 
+0.19 
+$ 
+0.22 
+Net income
+per common share — diluted 
+0.46 
+0.46 
+0.17 
+0.20 
+First 
+Second 
+Third 
+Fourth 
+2004 
+Quarter 
+Quarter 
+Quarter 
+Quarter 
+(In thousands, except per share data) 
+Total revenues 
+$ 
+31,919 
+$ 
+37,606 
+$ 
+25,138 
+$ 
+25,139 
+Income from operations 
+10,231 
+14,543 
+5,367 
+6,371 
+Net income 
+2,102 
+9,730 
+546 
+9,123 
+(b) 
+Net income per common share-basic 
+$ 
+0.13 
+$ 
+0.66 
+$ 
+0.01 
+$ 
+0.50 
+(b) 
+Net income per common share-diluted 
+0.12 
+0.58 
+0.01 
+0.45 
+(b) 
+(a) 
+These quarters were impacted by tropical storm and hurricane activity. 
+(b) 
+The fourth quarter of 2004 includes a tax benefit of $6.7 million resulting from the
+elimination of the valuation allowance established in 2003. See Note 3. 
+70
+Table of Contents 
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
+ACCOUNTING AND FINANCIAL DISCLOSURE 
+There have been no disagreements with the independent auditors on any matters of accounting
+principles or practices, financial statement disclosure, or auditing scope or procedures.
+ITEM 9.A CONTROLS AND PROCEDURES 
+The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the
+Securities Exchange Act of 1934, or the Exchange Act. This term refers to the controls and
+procedures of a company that are designed to ensure that information required to be disclosed by a
+company in the reports that it files or submits under the Exchange Act is recorded, processed,
+summarized and reported within the time periods specified by the Securities and Exchange
+Commission. Our management, including our Chief Executive Officer, has evaluated the effectiveness
+of our disclosure controls and procedures as of the end of the period covered by this annual
+report. Based upon that evaluation, our Chief Executive Officer has concluded that our disclosure
+controls and procedures were effective as of the end of the period covered by this annual report.
+There were no changes to our internal control over financial reporting during our last fiscal
+quarter that have materially affected, or are reasonable likely to materially affect, our internal
+control over financial reporting.
+Management’s Report On Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over
+financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the
+supervision and with the participation of our management, including our principal executive and
+financial officer, we conducted an evaluation of the effectiveness of our internal control over
+financial reporting as of December 31, 2005 based on the frame work in the Internal
+Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
+Commission. Based on our evaluation under the framework in Internal Control-Integrated Framework,
+our management concluded that our internal control over financial reporting was effective as of
+December 31, 2005.
+Ernst & Young LLP, our independent registered public accounting firm, has issued an attestation
+report on our management’s assessment of the effectiveness of our internal control over financial
+reporting which is included herein.
+71
+Table of Contents 
+Report of Independent Registered Public Accounting Firm
+The Stockholders and Board of Directors 
+Callon Petroleum Company
+We have audited management’s assessment, included in the accompanying Management’s Report on
+Internal Control over Financial Reporting, that Callon Petroleum Company maintained effective
+internal control over financial reporting as of December 31, 2005, based on criteria established in
+Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the
+Treadway Commission (COSO). Callon Petroleum Company’s management is responsible for
+maintaining effective internal control over financial reporting and for its assessment of the
+effectiveness of internal control over financial reporting. Our responsibility is to express an
+opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal
+control over financial reporting based on our audit.
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
+Board (United States). Those standards require that we plan and perform the audit to obtain
+reasonable assurance about whether effective internal control over financial reporting was
+maintained in all material respects. Our audit included obtaining an understanding of internal
+control over financial reporting, evaluating management’s assessment, testing and evaluating the
+design and operating effectiveness of internal control, and performing such other procedures as we
+considered necessary in the circumstances. We believe that our audit provides a reasonable basis
+for our opinion.
+A company’s internal control over financial reporting is a process designed to provide reasonable
+assurance regarding the reliability of financial reporting and the preparation of financial
+statements for external purposes in accordance with generally accepted accounting principles. A
+company’s internal control over financial reporting includes those policies and procedures that (1)
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
+transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
+transactions are recorded as necessary to permit preparation of financial statements in accordance
+with generally accepted accounting principles, and that receipts and expenditures of the company
+are being made only in accordance with authorizations of management and directors of the company;
+and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
+acquisition, use, or disposition of the company’s assets that could have a material effect on the
+financial statements.
+Because of its inherent limitations, internal control over financial reporting may not prevent or
+detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
+subject to the risk that controls may become inadequate because of changes in conditions, or that
+the degree of compliance with the policies or procedures may deteriorate.
+In our opinion, management’s assessment that Callon Petroleum Company maintained effective internal
+control over financial reporting as of December 31, 2005, is fairly stated, in all material
+respects, based on criteria established in Internal
+Control—Integrated Framework issued by the Committee of Sponsoring
+Organizations of the Trading Commission. Also, in our opinion, Callon Petroleum Company maintained,
+in all material respects, effective internal control over financial reporting as of December 31,
+2005, based on the COSO criteria.
+72
+Table of Contents 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight
+Board (United States), the consolidated balance sheets of Callon Petroleum Company as of December
+31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity and
+cash flows for each of the three years in the period ended December 31, 2005 of Callon Petroleum
+Company and our report dated March 9, 2006, expressed an unqualified opinion thereon.
+/s/ Ernst & Young LLP 
+New Orleans, Louisiana 
+March 9, 2006
+73
+Table of Contents 
+ITEM 9.B OTHER INFORMATION 
+We have disclosed all information required to be disclosed in a current report on Form 8-K during
+the fourth quarter of the year ended December 31, 2005 in previously filed reports on Form 8-K.
+74
+Table of Contents 
+PART III. 
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. 
+For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 4, 2006 which will be filed with the
+Securities and Exchange Commission and is incorporated herein by reference.
+The Company has adopted a code of ethics that applies to the Company’s chief executive officer,
+chief financial officer and chief accounting officer. The full text of such code of ethics has
+been posted on the Company’s website at ww.callon.com, and is available free of charge in print to
+any shareholder who requests it. Request for copies should be addressed to the Secretary at 200
+North Canal Street, Natchez, Mississippi 39120.
+ITEM 11. EXECUTIVE COMPENSATION. 
+For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 4, 2006 which will be filed with the
+Securities and Exchange Commission and is incorporated herein by reference.
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
+STOCKHOLDER MATTERS. 
+For information concerning the security ownership of certain beneficial owners and management, see
+the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of
+Stockholders on May 4, 2006 which will be filed with the Securities and Exchange Commission and is
+incorporated herein by reference.
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 4, 2006 which will be filed with the
+Securities and Exchange Commission and is incorporated herein by reference.
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES. 
+For information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 4, 2006 which will be filed with the
+Securities and Exchange Commission and is incorporated herein by reference.
+75
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0000928022/2005/0000950134-06-005141/item13.txt b/raw/filings/0000928022/2005/0000950134-06-005141/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..7a344b15f05a4a9a1cb1ced6ad024309226b077d
--- /dev/null
+++ b/raw/filings/0000928022/2005/0000950134-06-005141/item13.txt
@@ -0,0 +1,4 @@
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders on May 4, 2006 which will be filed with the
+Securities and Exchange Commission and is incorporated herein by reference.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2005/0000950134-06-005141/item9a.txt b/raw/filings/0000928022/2005/0000950134-06-005141/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2005/0000950134-06-005141/rp_note.txt b/raw/filings/0000928022/2005/0000950134-06-005141/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2005/0000950134-06-005141/rpt_disclosure.txt b/raw/filings/0000928022/2005/0000950134-06-005141/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..900696ae5d1d87c4ad86e368d04fbb8f800faa36
--- /dev/null
+++ b/raw/filings/0000928022/2005/0000950134-06-005141/rpt_disclosure.txt
@@ -0,0 +1,143 @@
+Related Persons Transactions Oversight . The Company shall not enter into a related
+person transaction unless such transaction is approved by the Committee after a review of
+the transaction for potential conflicts of interest. The terms “related person” and
+“transaction” shall have the meaning given such terms in Item 404 of Regulation S-K, as
+amended from time to time. If such related person transaction occurs and is approved by
+the Committee, the Committee shall review the disclosure(s) as required by Item 404. 
+9. 
+Risk Management Oversight . 
+9.1. 
+Risk Exposure . The Committee shall periodically meet with management and each
+Independent Auditor to review and discuss (a) guidelines and policies with respect to risk
+assessment and risk management to the extent necessary or appropriate to govern the process
+by which the Company’s risk assessment and management is undertaken and handled (although
+the Committee is not required to be the sole body responsible for risk assessment and
+management) and (b) the Company’s major financial risk exposures and the steps management
+has taken to monitor and control such exposures. If the Company manages and assesses its
+risk through mechanisms other than the Committee, the mechanisms need not 
+38 
+Table of Contents 
+be replaced by
+the Committee, but the processes in place should be reviewed in a general manner by the
+Committee. 
+9.2. 
+Insurance . The Committee shall periodically review and assess insurance coverage,
+including Directors and Officers Liability, property and casualty loss,
+errors and omissions and surety bonds, with management and, at the Committee’s discretion,
+General Counsel. 
+9.3. 
+Special-Purpose Entities and Off-Balance Sheet Transactions . The Committee shall
+periodically meet with management, the Internal Auditor, the General Counsel and the
+External Auditor to review and assess all “special-purpose” entities of the Company and all
+complex financing transactions involving the Company, including all related off-balance
+sheet accounting matters. 
+9.4. 
+Consultation with Legal Counsel . The Committee shall periodically, at its discretion,
+review with the General Counsel and, if the Committee deems it appropriate, outside legal
+counsel legal matters (including material claims, pending legal proceedings, government
+investigations and material reports, notices or inquires received from governmental
+agencies) that may have a significant impact on the Company’s financial statements or risk
+management. 
+10. 
+Reports and Assessments . 
+10.1. 
+Board Reports . The Chairperson of the Committee shall, periodically, at his or her
+discretion, report to the Board on Committee actions and on the fulfillment of the
+Committee’s responsibilities under this Charter. Such reports shall include any issues
+that arise with respect to the quality or integrity of the Company’s financial statements,
+the Company’s compliance with legal or regulatory requirements, the performance and
+independence of the Company’s External Auditors and the performance of the Company’s
+internal audit function. This report shall be presented and incorporated with and into the
+next regularly scheduled Board meeting. 
+10.2. 
+Charter Assessment . The Committee shall annually assess the adequacy of this Charter
+and advise the Board and the Nominating and Corporate Governance Committee of its
+assessment and of its recommendation for any changes to the Charter. The Committee shall,
+if requested by management, assist management with the preparation of a certification to be
+presented annually to the NYSE affirming that the Committee reviewed and reassessed the
+adequacy of this Charter. 
+10.3. 
+Committee Self-Assessment . The Committee shall annually make a self-assessment of its
+performance and shall report the results of such self-assessment to the Board and the
+Nominating and Corporate Governance Committee. 
+10.4. 
+Proxy Statement Report . The Committee shall prepare an annual report as required by
+the rules and regulations of the SEC and submit it to the Board for inclusion in the
+Company’s proxy statement prepared in connection with its annual meeting of stockholders. 
+39 
+Table of Contents 
+10.5. 
+Recommend Action . The Committee shall annually make a determination as to whether to
+recommend to the Board that the audited financials (certified by the External Auditor) be
+included in the Company’s annual report on Form 10-K for filing with the SEC. 
+10.6. 
+Board Access to External Auditor . The Committee shall, whenever the Board of
+Directors or the Committee deems it appropriate, have the External Auditor
+attend a meeting of the Board to discuss specific issues and to answer questions from the
+directors. 
+11. 
+General . 
+11.1. 
+Financial Statement Responsibility . The Company’s management is responsible for the
+preparation, presentation and integrity of the Company’s financial statements and
+disclosures, and the External Auditor is responsible for auditing year-end financial
+statements and reviewing quarterly financial statements and conducting other procedures.
+It is not the duty of the Committee to certify the Company’s financial statements, to
+guarantee the External Auditor’s report or to plan or conduct audits. Since the primary
+function of the Committee is oversight, the Committee shall be entitled to rely on the
+expertise, skills and knowledge of management, the Internal Auditor and the External
+Auditor and the accuracy of information provided to the Committee by such persons in
+carrying out its oversight responsibilities. Nothing in this Charter is intended to change
+the responsibilities of management and the External Auditor. 
+11.2. 
+Charter Guidelines . While the responsibilities of the Committee set forth in Section
+5 through 10 above are contemplated to be the principal recurring activities of the
+Committee in carrying out its oversight function, these responsibilities are to serve as a
+guide with the understanding that the Committee may diverge from them as it deems
+appropriate given the circumstances. 
+12. 
+Qualified Legal Compliance Committee Duties . 
+12.1. 
+Purpose . The Committee shall fulfill the requirements of a Qualified Legal Compliance
+Committee, as defined in Part 205 of Title 17, Chapter II of the Code of Federal
+Regulations ( “Part 205” ). 
+12.2. 
+Written Procedures . The Committee shall have the authority and responsibility to
+establish written procedures to confidentially receive, consider and retain reports of
+evidence of a material violation by the Company, its officers, directors, employees or
+agents of federal or state securities laws, material breach of fiduciary duty, or a similar
+material violation of any federal or state law. 
+12.3. 
+Report Submission . The Committee shall have the authority and responsibility to
+inform the Company’s chief legal officer, as such term is used in Part 205 ( “CLO” ), and CEO
+(or the equivalents thereof) of any report of evidence of a material violation (except in
+case of futility). 
+12.4. 
+Investigation Determination . The Committee shall determine whether an investigation
+is necessary regarding any report of evidence of a material violation by the Company, its
+officers, directors, employees or agents. If the Committee determines an investigation is
+necessary or appropriate, the 
+40 
+Table of Contents 
+Committee shall (i) notify the Board of its determination to
+investigate, (ii) initiate an investigation, which may be conducted either by the CLO (or
+the equivalent thereof) or by outside counsel, and (iii) retain such additional Advisors to
+assist in such investigation as the Committee deems necessary or appropriate. 
+12.5. 
+Conclusion of Investigation . At the conclusion of any investigation the Committee
+shall (i) have the authority and responsibility to recommend, by majority vote, that the
+Company implement an appropriate response to evidence
+of a material violation, and (ii) inform the Company’s CLO and CEO (or the equivalents
+thereof) and the Board of the results of any such investigation and the appropriate
+remedial measures to be adopted, if any. 
+12.6. 
+Notification of SEC . The Committee shall have the authority to take all other
+appropriate action, including the authority to notify the SEC in the event that the Company
+fails in any material respect to implement an appropriate response that the Committee has
+recommended the Company to take; provided, that the Committee determines, by
+majority vote and after consultation with counsel, that such notification would be required
+by law or in the best interest of the Company. 
+General Authority . The Committee shall have the authority to take any other action necessary to
+meet the requirements of a Qualified Legal Compliance Committee under Part 205.
+41 
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0000928022/2007/0000950134-08-004915/filing.txt b/raw/filings/0000928022/2007/0000950134-08-004915/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..39392f680c997e2e5233db095b266698c5699181
--- /dev/null
+++ b/raw/filings/0000928022/2007/0000950134-08-004915/filing.txt
@@ -0,0 +1,5202 @@
+10-K
+1
+d54908e10vk.htm
+FORM 10-K
+e10vk 
+Table of Contents 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF 
+THE SECURITIES EXCHANGE ACT OF 1934 
+FOR THE FISCAL YEAR ENDED DECEMBER 31, 2007 
+Commission File Number 001-14039 
+CALLON PETROLEUM COMPANY 
+(Exact name of Registrant as specified in its charter) 
+Delaware 
+64-0844345 
+(State or other jurisdiction of
+(I.R.S. Employer 
+incorporation or organization)
+Identification No.) 
+200 North Canal Street 
+Natchez, Mississippi 39120 
+(601) 442-1601 
+(Address of Principal Executive
+(Registrant’s telephone number 
+Offices)(Zip Code)
+including area code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class 
+Name of exchange on which registered 
+Common Stock, Par Value $.01 Per Share
+New York Stock Exchange 
+Securities registered pursuant to Section 12(g) of the Act: None 
+Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of
+the Securities Act.
+Yes o No þ .
+Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
+Section 15(d) of the Act. Yes
+o No þ .
+Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by
+Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
+such shorter period that the Registrant was required to file such reports), and (2) has been
+subject to such filing requirements for the past 90 days.
+Yes þ No o .
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
+not contained herein, and will not be contained, to the best of Registrant’s knowledge, in
+definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
+or any amendment to this Form 10-K. o 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
+filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large
+accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
+Exchange Act. (Check one):
+Large accelerated filer o 
+Accelerated filer þ 
+Non-accelerated filer o 
+(Do not check if a smaller reporting company) 
+Smaller reporting company o 
+Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule
+12b-2). Yes o 
+No þ .
+The aggregate market value of the voting and non-voting common equity held by nonaffiliates of the
+registrant was approximately $283 million as of June 30, 2007 (based on the last reported sale
+price of such stock on the New York Stock Exchange on such date of $19.34).
+As of March 10, 2008, there were 20,896,094 shares of the Registrant’s Common Stock, par value $.01
+per share, outstanding.
+Document incorporated by reference: Portions of the definitive Proxy Statement of Callon Petroleum
+Company (to be filed no later than 120 days after December 31, 2007) relating to the Annual Meeting
+of Stockholders to be held on May 1, 2008, which are incorporated into Part III of this Form 10-K.
+TABLE OF CONTENTS 
+PART I 
+ITEM 1 and 2. BUSINESS and PROPERTIES 
+ITEM 3. LEGAL PROCEEDINGS 
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 
+PART II 
+ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS 
+ITEM 6. SELECTED FINANCIAL DATA 
+ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS 
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+ITEM 9.A CONTROLS AND PROCEDURES 
+ITEM 9.B OTHER INFORMATION 
+PART III 
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 
+ITEM 11. EXECUTIVE COMPENSATION 
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES 
+PART IV 
+ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 
+SIGNATURES 
+Consent of Ernst & Young LLP 
+Consent of Huddleston & Co., Inc. 
+Certification of Chief Executive Officer Pursuant to Rule 13(a)-14(a) 
+Certification of Chief Financial Officer Pursuant to Rule 13(a)-14(a) 
+Certification of Chief Executive Officer Pursuant to Rule 13(a)-14(b) 
+Certification of Chief Financial Officer Pursuant to Rule 13(a)-14(b) 
+Table of Contents 
+PART I. 
+ITEM 1 and 2. BUSINESS and PROPERTIES 
+Overview 
+Callon Petroleum Company has been engaged in the exploration, development, acquisition and
+production of oil and gas properties since 1950. Our properties are geographically concentrated
+primarily offshore in the Gulf of Mexico and onshore in Louisiana. We were incorporated under the
+laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited
+partnership, a joint venture with a consortium of European investors and an independent energy
+company owned by a member of current management. As used herein, the “Company,” “Callon,” “we,”
+“us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the
+context requires otherwise.
+In 1989, we began increasing our reserves through the acquisition of producing properties that were
+geologically complex, had (or were analogous to fields with) an established production history from
+stacked pay zones and were candidates for exploitation. We focused on reducing operating costs and
+implementing production enhancements through the application of technologically advanced production
+and recompletion techniques.
+Over the past 12 years, we have placed emphasis on the acquisition of acreage with exploration and
+development drilling opportunities in the Gulf of Mexico shelf and deepwater areas. At December
+31, 2007, we owned working interests in a total of 104 blocks/leases covering 212,000 net acres.
+To minimize risk we join with industry partners to explore federal offshore blocks acquired in the
+Gulf of Mexico. We perform extensive geological and geophysical studies using computer-aided
+exploration techniques (CAEX), including, where appropriate, the acquisition of 3-D seismic or
+high-resolution 2-D data to facilitate these efforts. We continue to develop prospects on the
+shelf through our 3-D seismic partnership using Amplitude versus Offset (“AVO”) technology. We
+have approximately 20,000 square miles of 3-D seismic data and have invested in pre-stack time
+migration in order to apply AVO de-risking to our prospects. In 1998, we began exploration in the
+Gulf of Mexico deepwater area (generally 900 to 5,500 feet of water) and during the fourth quarter
+of 2003, our first two deepwater projects, the Medusa and Habanero fields, began production. In
+April, 2007 we acquired from BP Exploration and Production Company (“BP”) their 80% interest in the
+Entrada field which is located in the deepwater region of the Gulf of Mexico. We now own a 100%
+interest, operate and have begun development of the field. Expected production from this deepwater
+discovery is currently projected to be in early 2009. Please see “Significant Properties” for a
+more detailed discussion.
+On February 11, 2008, we entered into an agreement to sell 50% of our working interest in the
+Entrada Field to CIECO Energy (US) Company (“CIECO”) effective January 1, 2008 for a purchase price
+of $175 million with a cash payment of $155 million due at closing and the additional $20 million
+payable after the achievement of certain production milestones.
+Additional contingent cash payments could be payable based on
+additional cumulative production milestones. Also, CIECO has agreed to finance our
+50% share of the estimated $300 million development costs for the Entrada field. Please see “Note
+14 — Entrada Acquisition and Development” for more details.
+We ended the year 2007 with estimated net proved reserves of 263.6 billion cubic feet of natural
+gas equivalent (“Bcfe”). This represents an increase of 81% from 2006 year-end estimated net
+proved reserves of 145.6 Bcfe.
+The major focus of our future operations is expected to continue to be the exploration for and
+development of oil and gas properties, primarily in the Gulf of Mexico.
+2 
+Table of Contents 
+Availability of Reports 
+All of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
+8-K, and amendments to such reports as well as other filings we make pursuant to Section 13(a) and
+15(d) of the Securities Exchange Act of 1934 are available free of charge on our Internet website.
+The address of our Internet website is www.callon.com. Our Securities and Exchange Commission
+(“SEC”) filings are available on our website as soon as they are posted to the EDGAR database on
+the SEC’s website.
+Business Strategy 
+Our goal is to increase shareholder value by increasing our reserves, production, cash flow and
+earnings. We seek to achieve these goals through the following strategies:
+• 
+focus on Gulf of Mexico exploration with a balance between shelf and deepwater areas,
+and onshore Louisiana; 
+• 
+aggressively explore our existing prospect inventory; 
+• 
+replenish our prospect inventory with increasing emphasis on prospect generation using
+AVO technology to reduce the risks associated with our exploratory drilling; and 
+• 
+acquire producing properties with infrastructure in areas of focus that contain upside
+potential. 
+Exploration and Development Activities 
+In 2007, capital expenditures for exploration and development costs related to oil and gas
+properties totaled approximately $124 million. These expenditures included:
+• 
+$37 million in the Gulf of Mexico shelf, onshore south Louisiana and Texas state waters
+areas which included the drilling of six exploratory wells, two of which were unsuccessful
+and two of which were in progress at the end of 2007. In addition, the $37 million
+included the cost of one development well and completion costs for our successful wells; 
+• 
+$33 million in our deepwater area, excluding our Entrada discovery, which included one
+exploratory well, Bob North which was dry, and one development well at our Habanero field; 
+• 
+$16 million on long-lead items and engineering for our Entrada discovery; 
+• 
+$17 million for leasehold and seismic costs; 
+• 
+$3 million for plugging and abandonment costs; and 
+• 
+$7 million for capitalized interest and $11 million for capitalized general and
+administration costs allocable directly to exploration and development projects. 
+Acquisitions and Divestitures 
+In April 2007, we acquired BP’s 80% working interest in the deepwater Gulf of Mexico discovery,
+Entrada, for a purchase price of $190 million, which included $150 million payable at closing and
+an additional $40 million payable after the achievement of certain production milestones. To
+strengthen our balance sheet and provide additional liquidity for the development of our Gulf of
+Mexico deepwater fields, primarily Entrada, we completed the sale of certain non-core, non-operated
+royalty and mineral interests for $61.5 million in December 2007.
+Subsequent to December 31, 2007, we entered into an agreement to sell 50% of our working interest
+in the Entrada field to CIECO for a purchase price of $175 million with a cash payment of $155
+million at
+3 
+Table of Contents 
+closing and the additional $20 million payable after the achievement of certain
+production milestones. Additional contingent cash payments could be payable based on
+additional cumulative production milestones. Please see “Note 14 — Entrada Acquisition and Development” for more
+details.
+Risk Factors 
+A decrease in oil and gas prices may adversely affect our results of operations and financial
+condition . Our success is highly dependent on prices for oil and gas, which are extremely volatile.
+Any substantial or extended decline in the price of oil or gas would have a material adverse effect
+on us. Oil and gas markets are both seasonal and cyclical. The prices of oil and gas depend on
+factors we cannot control such as weather, economic conditions, and levels of production, actions
+by OPEC and other countries and government actions. Prices of oil and gas will affect the following
+aspects of our business:
+• 
+our revenues, cash flows and earnings; 
+• 
+the amount of oil and gas that we are economically able to produce; 
+• 
+our ability to attract capital to finance our operations and the cost of the capital; 
+• 
+the amount we are allowed to borrow under our senior secured credit facility; 
+• 
+the value of our oil and gas properties; and 
+• 
+the profit or loss we incur in exploring for and developing our reserves. 
+Our reserve information represents estimates that may turn out to be incorrect if the assumptions
+upon which these estimates are based are inaccurate. Any material inaccuracies in these reserve
+estimates or underlying assumptions will materially affect the quantities and present value of our
+reserves. The process of estimating oil and gas reserves is complex. It requires interpretations
+of available technical data and various assumptions, including assumptions relating to economic
+factors. Any significant inaccuracies in these interpretations or assumptions could materially
+affect the estimated quantities and present value of reserves shown in this annual report.
+In order to prepare these estimates, we must project production rates and the timing of development
+expenditures. The assumptions regarding the timing and costs to commence production from our
+deepwater wells used in preparing our reserves are often subject to revisions over time as
+described under “Our deepwater operations have special operational risks that may negatively affect
+the value of those assets.” We must also analyze available geological, geophysical, production and
+engineering data, the extent, quality and reliability of which can vary. The process also requires
+us to make economic assumptions, such as oil and gas prices, drilling and operating expenses,
+capital expenditures, taxes and availability of funds. Therefore, estimates of oil and gas
+reserves are inherently imprecise.
+Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating
+expenses and quantities of recoverable oil and gas reserves most likely will vary from the
+estimates. Any significant variance could materially affect the estimated quantities and present
+value of reserves shown in this report. In addition, estimates of proved reserves may be adjusted
+to reflect production history, results of exploration and development, prevailing oil and gas
+prices and other factors, many of which are beyond our control.
+Also, under Mineral Management Services (“MMS”) rules governing our deepwater Medusa property and
+several of our shallow water, deep natural gas properties and prospects, we are eligible for
+royalty suspensions depending on the difference between the average monthly New York Mercantile
+Exchange (NYMEX) sales price for oil or gas and price thresholds set by the MMS. As a result, our
+reserve estimates may increase or decrease depending upon the relation of price thresholds versus
+the average NYMEX prices.
+4 
+Table of Contents 
+Our Entrada field is governed by leases from the MMS. These leases granted royalty suspension
+without provisions for pricing thresholds for crude oil and natural gas which would require us to
+pay royalties to the MMS if the thresholds were exceeded by the current year average of NYMEX
+prices. The MMS has
+notified us that the exclusion of the provisions for the pricing threshold occurred in error in the
+lease issuance process and was not the MMS’s intention. Congress is considering various bills to
+address this issue, and if a bill were to pass to amend the leases to provide thresholds for crude
+oil and natural gas prices, the reserves for Entrada could be subject to royalties. However, the
+MMS stated in their correspondence to us they will continue to honor the terms of the leases as
+issued unless notified otherwise. This correspondence applies only to our original 20% working
+interest in the Entrada Field.
+You should not assume that the present value of future net cash flows from our proved reserves
+referred to in this report is the current market value of our estimated oil and gas reserves. In
+accordance with SEC requirements, we generally base the estimated discounted future net cash flows
+from our proved reserves on prices and costs on the date of the estimate. Actual future prices and
+costs may differ materially from those used in the present value estimate.
+The discounted present value of our oil and gas reserves is prepared in accordance with guidelines
+established by the SEC. A purchaser of reserves would use numerous other factors to value the
+reserves. The discounted present value of reserves, therefore, does not necessarily represent the
+fair market value of those reserves.
+On December 31, 2007, approximately 80% of the discounted present value of our estimated net proved
+reserves was proved undeveloped. Proved undeveloped reserves represented 81% of total proved
+reserves. Most of these proved undeveloped reserves were attributable to our deepwater properties.
+Development of these properties is subject to additional risks as described above.
+Information about reserves constitutes forward-looking information. See “Forward-Looking
+Statements” for information regarding forward-looking information. 
+Unless we are able to replace reserves which we have produced, our cash flows and production will
+decrease over time. Our future success depends upon our ability to find, develop and acquire oil
+and gas reserves that are economically recoverable. As is generally the case for Gulf properties,
+our producing properties usually have high initial production rates, followed by a steep decline in
+production. As a result, we must continually locate and develop or acquire new oil and gas reserves
+to replace those being depleted by production. We must do this even during periods of low oil and
+gas prices when it is difficult to raise the capital necessary to finance these activities and
+during periods of high operating costs when it is expensive to contract for drilling rigs and other
+equipment and personnel necessary to explore for oil and gas. Without successful exploration or
+acquisition activities, our reserves, production and revenues will decline rapidly. We cannot
+assure you that we will be able to find and develop or acquire additional reserves at an acceptable
+cost.
+Also, because of the aggregate short life of our reserves, our return on the investment we make in
+our oil and gas wells and the value of our oil and gas wells will depend significantly on prices
+prevailing during relatively short production periods.
+A significant part of the value of our production and reserves is concentrated in a small number of
+offshore properties, and any production problems or inaccuracies in reserve estimates related to
+those properties would adversely impact our business. During 2007, approximately 63% of our daily
+production came from five of our properties in the Gulf of Mexico. Moreover, one property accounted
+for
+5 
+Table of Contents 
+24% of our production during this period. In addition, at December 31, 2007, most of our proved
+reserves were located in three fields in the Gulf of Mexico, with approximately 92% of our total
+net proved reserves attributable to these properties. If mechanical problems, storms or other
+events curtailed a substantial portion of this production or if the actual reserves associated with
+any one of these producing
+properties are less than our estimated reserves, our results of operations and financial condition
+could be adversely affected.
+Our focus on exploration projects increases the risks inherent in our oil and gas activities. Our
+business strategy focuses on replacing reserves through exploration, where the risks are greater
+than in acquisitions and development drilling. Although we have been successful in exploration in
+the past, we cannot assure you that we will continue to increase reserves through exploration or at
+an acceptable cost. Additionally, we are often uncertain as to the future costs and timing of
+drilling, completing and producing wells. Our drilling operations may be curtailed, delayed or
+canceled as a result of a variety of factors, including:
+• 
+unexpected drilling conditions; 
+• 
+pressure or inequalities in formations; 
+• 
+equipment failures or accidents; 
+• 
+adverse weather conditions; 
+• 
+governmental requirements; and 
+• 
+shortages or delays in the availability of drilling rigs and the delivery of equipment. 
+We do not operate all of our properties and have limited influence over the operations of some of
+these properties, particularly two of our deepwater properties. Our lack of control could result
+in the following:
+• 
+the operator may initiate exploration or development at a faster or slower pace than we
+prefer; 
+• 
+the operator may propose to drill more wells or build more facilities on a project than
+we have funds for or that we deem appropriate, which may mean that we are unable to
+participate in the project or share in the revenues generated by the project even though we
+paid our share of exploration costs; and 
+• 
+if an operator refuses to initiate a project, we may be unable to pursue the project. 
+Any of these events could materially reduce the value of our non-operated properties.
+Our deepwater operations have special operational risks that may negatively affect the value of
+those assets. Drilling operations in the deepwater area are by their nature more difficult and
+costly than drilling operations in shallow water. Deepwater drilling operations require the
+application of more advanced drilling technologies involving a higher risk of technological failure
+and usually have significantly higher drilling costs than shallow water drilling operations.
+Deepwater wells are completed using sub-sea completion techniques that require substantial time and
+the use of advanced remote installation equipment. These operations involve a high risk of
+mechanical difficulties and equipment failures that could result in significant cost overruns.
+In deepwater, the time required to commence production following a discovery is much longer than in
+shallow water and on-shore. Deepwater discoveries require the construction of expensive production
+facilities and pipelines prior to production. We cannot estimate the costs and timing of the
+construction of these facilities with certainty, and the accuracy of our estimates will be affected
+by a number of factors beyond our control, including the following:
+6 
+Table of Contents 
+• 
+decisions made by the operators of our deepwater wells; 
+• 
+the availability of materials necessary to construct the facilities; 
+• 
+the proximity of our discoveries to pipelines; 
+• 
+the price of oil and natural gas; and 
+• 
+regulatory requirements. 
+Delays and cost overruns in the commencement of production will affect the value of our deepwater
+prospects and the discounted present value of reserves attributable to those prospects.
+Competitive industry conditions may negatively affect our ability to conduct operations. We
+operate in the highly competitive areas of oil and gas exploration, development and production. We
+compete for the purchase of leases in the Gulf of Mexico granted by the U. S. government and from
+other oil and gas companies. These leases include exploration prospects as well as properties with
+proved reserves. Factors that affect our ability to compete in the marketplace include:
+• 
+our access to the capital necessary to drill wells and acquire properties; 
+• 
+our ability to acquire and analyze seismic, geological and other information relating to
+a property; 
+• 
+our ability to retain the personnel necessary to properly evaluate seismic and other
+information relating to a property; 
+• 
+the location of, and our ability to access, platforms, pipelines and other facilities
+used to produce and transport oil and gas production; 
+• 
+the standards we establish for the minimum projected return on an investment of our
+capital; and 
+• 
+the availability of alternate fuel sources. 
+Our competitors include major integrated oil companies, substantial independent energy companies,
+and affiliates of major interstate and intrastate pipelines and national and local gas gatherers,
+many of which possess greater financial, technological and other resources than we do.
+Our competitors may use superior technology, which we may be unable to afford or which would
+require costly investment by us in order to compete. Our industry is subject to rapid and
+significant advancements in technology, including the introduction of new products and services
+using new technologies. As our competitors use or develop new technologies, we may be placed at a
+competitive disadvantage, and competitive pressures may force us to implement new technologies at a
+substantial cost. In addition, our competitors may have greater financial, technical and personnel
+resources that allow them to enjoy technological advantages and may in the future allow them to
+implement new technologies before we can. We cannot be certain that we will be able to implement
+technologies on a timely basis or at a cost that is acceptable to us. One or more of the
+technologies that we currently use or that we may implement in the future may become obsolete, and
+we may be adversely affected. For example, marine seismic acquisition technology has been
+characterized by rapid technological advancements in recent years, and further significant
+technological developments could substantially impair our 3-D seismic data’s value.
+We may not be able to replace our reserves or generate cash flows if we are unable to raise
+capital. We will be required to make substantial capital expenditures to develop our existing
+reserves, and to discover new oil and gas reserves. Historically, we have financed these
+expenditures primarily with cash from operations, proceeds from bank borrowings and proceeds from
+the sale of debt and equity securities. See “Management’s Discussion and Analysis of Financial
+Condition and Results of Operations — Liquidity and Capital Resources” for a discussion of our
+capital budget. We cannot assure you that we
+7 
+Table of Contents 
+will be able to raise capital in the future. We also
+make offers to acquire oil and gas properties in the ordinary course of our business. If these
+offers are accepted, our capital needs may increase substantially.
+We expect to continue using our senior secured credit facility to borrow funds to supplement our
+available cash. The amount we may borrow under our senior secured credit facility may not exceed a
+borrowing base determined by the lenders under such facility based on their projections of our
+future production, production costs, taxes, commodity prices and any other factors deemed relevant
+by our lenders. We
+cannot control the assumptions the lenders use to calculate our borrowing base. The lenders may,
+without our consent, adjust the borrowing base semiannually or in situations where we purchase or
+sell assets or issue debt securities. If our borrowings under the senior secured credit facility
+exceed the borrowing base, the lenders may require that we repay the excess. If this were to occur,
+we might have to sell assets or seek financing from other sources. Sales of assets could further
+reduce the amount of our borrowing base. We cannot assure you that we would be successful in
+selling assets or arranging substitute financing. If we were not able to repay borrowings under
+our senior secured credit facility to reduce the outstanding amount to less than the borrowing
+base, we would be in default under our senior secured credit facility. For a description of our
+senior secured credit facility and its principal terms and conditions, see “Management’s Discussion
+and Analysis of Financial Condition and Results of Operations —Liquidity and Capital Resources”
+and Note 7 to our Consolidated Financial Statements.
+Our decision to drill a prospect is subject to a number of factors, and we may decide to alter our
+drilling schedule or not drill at all. A prospect is a property on which we have identified what
+our geoscientists believe, based on available seismic and geological information, to be indications
+of hydrocarbons. Our prospects are in various stages of evaluation, ranging from a prospect which
+is ready to drill to a prospect which will require substantial additional seismic data processing
+and interpretation. Whether we ultimately drill a prospect may depend on the following factors:
+• 
+receipt of additional seismic data or the reprocessing of existing data; 
+• 
+material changes in oil or gas prices; 
+• 
+the costs and availability of drilling rigs; 
+• 
+the success or failure of wells drilled in similar formations or which would use the
+same production facilities; 
+• 
+availability and cost of capital; 
+• 
+changes in the estimates of the costs to drill or complete wells; 
+• 
+our ability to attract other industry partners to acquire a portion of the working
+interest to reduce exposure to costs and drilling risks; and 
+• 
+decisions of our joint working interest owners. 
+We will continue to gather data about our prospects and it is possible that additional information
+may cause us to alter our drilling schedule or determine that a prospect should not be pursued at
+all. You should understand that our plans regarding our prospects are subject to change.
+Weather, unexpected subsurface conditions, and other unforeseen operating hazards may adversely
+impact our ability to conduct business. There are many operating hazards in exploring for and
+producing oil and gas, including:
+• 
+our drilling operations may encounter unexpected formations or pressures, which could
+cause damage to equipment or personal injury; 
+• 
+we may experience equipment failures which curtail or stop production; 
+8 
+Table of Contents 
+• 
+we could experience blowouts or other damages to the productive formations that may
+require a well to be re-drilled or other corrective action to be taken; and 
+• 
+because of these or other events, we could experience environmental hazards, including
+release of oil and gas from spills, gas leaks, and ruptures. 
+In the event of any of the foregoing, we may be subject to interrupted production or substantial
+environmental liability due to injury to persons or loss of life, damage to or destruction of
+property, natural resources and equipment, pollution and other environmental damage, investigation
+and remediation requirements, and fines and penalties and injunctive relief. Moreover, a
+substantial portion of
+our operations are offshore and are subject to a variety of risks peculiar to the marine
+environment such as capsizing, collisions, hurricanes and other adverse weather conditions, which
+can result in substantial damage to facilities and interrupt production, as well as more extensive
+governmental regulation.
+We cannot assure you that we will be able to maintain adequate insurance at rates we consider
+reasonable to cover our possible losses from operating hazards. The occurrence of a significant
+event not fully insured or indemnified against could materially and adversely affect our financial
+condition and results of operations.
+We may not have production to offset hedges; by hedging, we may not benefit from price increases. 
+Part of our business strategy is to reduce our exposure to the volatility of oil and gas prices by
+hedging a portion of our production. In a typical hedge transaction, we will have the right to
+receive from the other parties to the hedge the excess of the fixed price specified in the hedge
+over a floating price based on a market index, multiplied by the quantity hedged. If the floating
+price exceeds the fixed price, we are required to pay the other parties this difference multiplied
+by the quantity hedged. We are required to pay the difference between the floating price and the
+fixed price when the floating price exceeds the fixed price regardless of whether we have
+sufficient production to cover the quantities specified in the hedge. Significant reductions in
+production at times when the floating price exceeds the fixed price could require us to make
+payments under the hedge agreements even though such payments are not offset by sales of
+production. Hedging will also prevent us from receiving the full advantage of increases in oil or
+gas prices above the fixed amount specified in the hedge. We also enter into price “collars” to
+reduce the risk of changes in oil and gas prices. Under a collar, no payments are due by either
+party so long as the market price is above a floor set in the collar and below a ceiling. If the
+price falls below the floor, the counter-party to the collar pays the difference to us and if the
+price is above the ceiling, we pay the counter-party the difference. Another type of hedging
+contract we have entered into is a put contract. Under a put, if the price falls below the set
+floor price, the counter-party to the contract pays the difference to us. See “Quantitative and
+Qualitative Disclosures About Market Risks” for a discussion of our hedging practices.
+Compliance with environmental and other government regulations could be costly and could negatively
+impact production. Our operations are subject to numerous laws and regulations governing the
+operation and maintenance of our facilities and the discharge of materials into the environment or
+otherwise relating to environmental protection. For a discussion of the material regulations
+applicable to us, see “Regulations”. These laws and regulations may:
+• 
+require that we acquire permits before commencing drilling; 
+• 
+impose operational and other conditions on our activities; 
+• 
+restrict the substances that can be released into the environment in connection with
+drilling and production activities; 
+• 
+limit or prohibit drilling activities on protected areas such as wetlands, wilderness
+areas or coral reefs; and 
+9 
+Table of Contents 
+• 
+require measures to remediate or mitigate pollution and environmental impacts from
+current and former operations, such as cleaning up spills or dismantling abandoned
+production facilities. 
+Under these laws and regulations, we could be liable for costs of investigation, removal and
+remediation, damages to and loss of use of natural resources, loss of profits or impairment of
+earning capacity, property damages, costs of and increased public services, as well as
+administrative, civil and criminal fines and penalties, and injunctive relief. Under the common
+law, we could be liable for injuries to people and property. We maintain limited insurance
+coverage for sudden and accidental environmental damages. We do not believe that insurance coverage
+for environmental damages that occur over time is available at a reasonable cost. Also, we do not
+believe that insurance coverage for the full potential liability that could
+be caused by sudden and accidental environmental damages is available at a reasonable cost.
+Accordingly, we may be subject to liability or we may be required to cease production from
+properties in the event of environmental incidents.
+Factors beyond our control affect our ability to market production and our financial results. The
+ability to market oil and gas from our wells depends upon numerous factors beyond our control.
+These factors include:
+• 
+the extent of domestic production and imports of oil and gas; 
+• 
+the proximity of the gas production to gas pipelines; 
+• 
+the availability of pipeline capacity; 
+• 
+the demand for oil and gas by utilities and other end users; 
+• 
+the availability of alternative fuel sources; 
+• 
+the effects of inclement weather; 
+• 
+state and federal regulation of oil and gas marketing; and 
+• 
+federal regulation of gas sold or transported in interstate commerce. 
+Because of these factors, we may be unable to market all of the oil or gas we produce. In addition,
+we may be unable to obtain favorable prices for the oil and gas we produce.
+If oil and gas prices decrease, we may be required to take writedowns of the carrying value of our
+oil and gas properties. We may be required to writedown the carrying value of our oil and gas
+properties when oil and gas prices are low or if we have substantial downward adjustments to our
+estimated net proved reserves, increases in our estimates of development costs or deterioration in
+our exploration results. Under the full-cost method which we use to account for our oil and gas
+properties, the net capitalized costs of our oil and gas properties may not exceed the present
+value, discounted at 10%, of future net cash flows from estimated net proved reserves, using period
+end oil and gas prices or prices as of the date of our auditor’s report, plus the lower of cost or
+fair market value of our unproved properties. If net capitalized costs of our oil and gas
+properties exceed this limit, we must charge the amount of the excess to earnings. This type of
+charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity.
+We review the carrying value of our properties quarterly, based on prices in effect as of the end
+of each quarter or at the time of reporting our results. Once incurred, a writedown of oil and gas
+properties is not reversible at a later date, even if prices increase.
+There are inherent limitations in all control systems, and misstatements due to error or fraud that
+could seriously harm our business may occur and not be detected. Our management, including our
+Chief Executive and Financial Officers, do not expect that our internal controls and disclosure
+controls will prevent all possible error and all fraud. A control system, no matter how well
+conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of
+the control system are
+10 
+Table of Contents 
+met. In addition, the design of a control system must reflect the fact that
+there are resource constraints and the benefit of controls must be relative to their costs.
+Because of the inherent limitations in all control systems, an evaluation of controls can only
+provide reasonable assurance that all material control issues and instances of fraud, if any, in
+our company have been detected. These inherent limitations include the realities that judgments in
+decision-making can be faulty and that breakdowns can occur because of simple error or mistake.
+Further, controls can be circumvented by the individual acts of some persons or by collusion of two
+or more persons. The design of any system of controls is based in part upon certain assumptions
+about the likelihood of future events, and there can be no assurance that any design will succeed
+in achieving its stated goals under all potential future conditions. Because of inherent
+limitations in a cost-effective control system, misstatements due to error or fraud may occur and
+not be detected. A
+failure of our controls and procedures to detect error or fraud could seriously harm our business
+and results of operations.
+Forward-Looking Statements 
+In this report, we have made many forward-looking statements. We cannot assure you that the plans,
+intentions or expectations upon which our forward-looking statements are based will occur. Our
+forward-looking statements are subject to risks, uncertainties and assumptions, including those
+discussed elsewhere in this report. Forward-looking statements include statements regarding:
+• 
+our oil and gas reserve quantities, and the discounted present value of these
+reserves; 
+• 
+the amount and nature of our capital expenditures; 
+• 
+drilling of wells; 
+• 
+the timing and amount of future production and operating costs; 
+• 
+business strategies and plans of management; and 
+• 
+prospect development and property acquisitions. 
+Some of the risks, which could affect our future results and could cause results to differ
+materially from those expressed in our forward-looking statements, include:
+• 
+general economic conditions; 
+• 
+the volatility of oil and natural gas prices; 
+• 
+the uncertainty of estimates of oil and natural gas reserves; 
+• 
+the impact of competition; 
+• 
+the availability and cost of seismic, drilling and other equipment; 
+• 
+operating hazards inherent in the exploration for and production of oil and natural
+gas; 
+• 
+difficulties encountered during the exploration for and production of oil and
+natural gas; 
+• 
+difficulties encountered in delivering oil and natural gas to commercial markets; 
+• 
+changes in customer demand and producers’ supply; 
+• 
+the uncertainty of our ability to attract capital; 
+• 
+compliance with, or the effect of changes in, the extensive governmental
+regulations regarding the oil and natural gas business; 
+• 
+actions of operators of our oil and gas properties; and 
+• 
+weather conditions; and 
+• 
+climate change. 
+The information contained in this report, including the information set forth under the heading
+“Risk Factors,” identifies additional factors that could affect our operating results and
+performance. We urge you to carefully consider these factors and the other cautionary statements in
+this report. Our forward-looking
+11 
+Table of Contents 
+statements speak only as of the date made, and we have no
+obligation to update these forward-looking statements.
+Corporate Offices 
+Our headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned
+space. We also maintain a business office in Houston, Texas, and own or lease field offices in the
+area of the major fields in which we operate properties or have a significant interest. Replacement
+of any of our leased offices would not result in material expenditures by us as alternative
+locations to our leased space are anticipated to be readily available . 
+Employees 
+We had 85 employees as of December 31, 2007, none of whom are currently represented by a union. We
+believe that we have good relations with our employees. We employ seven petroleum engineers and
+eight petroleum geoscientists.
+Regulations 
+General . The oil and gas industry is subject to regulation at the federal, state and local level,
+and some of the laws, rules and regulations that govern our operations carry substantial penalties
+for non-compliance. This regulatory burden increases our cost of doing business and, consequently,
+affects our profitability.
+Exploration and Production. Our operations are subject to federal, state and local regulations
+that include requirements for permits to drill and to conduct other operations and for provision of
+financial assurances (such as bonds) covering drilling and well operations. Other activities
+subject to regulation are:
+• 
+the location of wells, 
+• 
+the method of drilling and completing wells, 
+• 
+the rate of production, 
+• 
+the surface use and restoration of properties upon which wells are drilled, 
+• 
+the plugging and abandoning of wells, 
+• 
+the discharge of contaminants into water and the emission of contaminants into air, 
+• 
+the disposal of fluids used or other wastes obtained in connection with operations, 
+• 
+the marketing, transportation and reporting of production, and 
+• 
+the valuation and payment of royalties. 
+For instance, our OCS leases in federal waters are administered by MMS, and require compliance with
+detailed MMS regulations and orders. Lessees must obtain MMS approval for exploration plans and
+exploitation and production plans prior to the commencement of such operations. The MMS has
+promulgated regulations requiring offshore production facilities located on the OCS to meet
+stringent engineering and construction specifications. The MMS also has regulations restricting
+the flaring or venting of natural gas, and prohibiting the flaring of liquid hydrocarbons and oil
+without prior authorization. MMS policies concerning the volume of production that a lessee must
+have to maintain an offshore lease beyond its primary term also are applicable to Callon.
+Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of
+wells located offshore and the installation and removal of all production facilities. To cover the
+various obligations of lessees on the OCS, the MMS generally requires that lessees have substantial
+net worth or post bonds or other acceptable assurances that
+12 
+Table of Contents 
+such obligations will be met. The cost
+of these bonds or other surety can be substantial, and there is no assurance that bonds or other
+surety can be obtained in all cases. Under some circumstances, the MMS may require any of our
+operations on federal leases to be suspended or terminated. Any such suspension or termination
+could materially adversely affect our financial conditions and results of operations.
+Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline
+transportation. The price and terms for access to pipeline transportation remain subject to
+extensive federal regulation. If these regulations change, we could face higher transmission costs
+for our production and, possibly, reduced access to transmission capacity.
+We do not currently anticipate that compliance with existing laws and regulations governing
+exploration and production will have a significantly adverse effect upon our capital expenditures,
+earnings or competitive position.
+Various proposals and proceedings that might affect the petroleum industry are pending before
+Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the
+courts. The industry historically has been heavily regulated and we can offer you no assurance
+that the less stringent regulatory approach recently pursued by the FERC and Congress will continue
+nor can we predict what effect such proposals or proceedings may have on our operations.
+Environmental Regulation. Various federal, state and local laws and regulations concerning the
+release of contaminants into the environment, including the discharge of contaminants into water
+and the emission of contaminants into the air, the generation, storage, treatment, transportation
+and disposal of wastes, and the protection of public health, welfare, and safety, and the
+environment, including natural resources, affect our exploration, development and production
+operations, including operations of our processing facilities. We must take into account the cost
+of complying with environmental regulations in planning, designing, drilling, constructing,
+operating and abandoning wells. Regulatory requirements relate to, among other things, the handling
+and disposal of drilling and production waste products, the control of water and air pollution and
+the removal, investigation, and remediation of petroleum-product contamination. In addition, our
+operations may require us to obtain permits for, among other things,
+• 
+air emissions, 
+• 
+discharges into surface waters, and 
+• 
+the construction and operations of underground injection wells or surface pits to
+dispose of produced saltwater and other nonhazardous oilfield wastes. 
+In the event of an unauthorized discharge, emission or other activity, we may be liable for, among
+other things, penalties, costs and damages, and subject to injunctive relief, and we could be
+required to cleanup or mitigate the environmental impacts of those discharges, emissions or
+activities. Under state and federal laws, the present and certain past owners and operators [of a
+site, and persons that treated, disposed of or arranged for the disposal of hazardous substances
+found at a site, may be liable, without regard to fault or the legality of the original conduct,
+for the release of hazardous substances into the environment. The Environmental Protection Agency,
+state environmental agencies and, in some cases third parties are authorized to take actions in
+response to threats to human health or the environment and to seek to recover from responsible
+classes of persons the costs of such] actions. We therefore could be required to remove or
+remediate previously disposed wastes and remediate contamination, including contamination in
+surface water, soil or groundwater, caused by disposal of that waste, irrespective of whether
+disposal or release were authorized. We could be responsible for wastes disposed of or released by
+us or prior owners or operators at properties owned or leased by us or at locations where wastes
+have been taken for disposal
+13 
+Table of Contents 
+also irrespective of whether disposal or release were authorized. We
+could also be required to suspend or cease operations in contaminated areas, or to perform remedial
+well plugging operations or cleanups to prevent future contamination.
+The Environmental Protection Agency and various state agencies have limited the disposal options
+for hazardous and nonhazardous wastes increasing costs of disposal. Furthermore, certain wastes
+generated by our oil and natural gas operations that are currently exempt from treatment as
+hazardous wastes may in the future be designated as hazardous wastes and, therefore, be subject to
+considerably more rigorous and costly operating and disposal requirements.
+Federal and state occupational safety and health laws require us to organize information about
+hazardous materials used, released or produced in our operations. Certain portions of this
+information must be provided to employees, state and local governmental authorities and local
+citizens. We are also subject to the requirements and reporting set forth in federal workplace
+standards.
+Recent scientific studies have suggested that man made emissions of certain gases, commonly
+referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to
+the warming of the atmosphere resulting in climate change. In response to such studies, the United
+States Congress is actively considering legislation to reduce emissions of greenhouse gases. In
+addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse
+gases, primarily through the planned development of greenhouse gas emission inventories and/or
+regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s
+decision on April 2, 2007 in Massachusetts v. EPA, the EPA may regulate greenhouse gas emissions
+from mobile sources (e.g., cars and trucks) and possibly from stationary sources as well under
+certain federal Clean Air Act programs, even if Congress does not adopt new legislation
+specifically addressing emissions of greenhouse gases. New legislation or regulatory programs that
+restrict emissions of greenhouse gases in areas where we conduct business could adversely affect
+our operations and the demand for hydrocarbon products generally. The impact of such future
+programs cannot be predicted, but we do not expect our operations to be affected any differently
+than other similarly situated domestic competitors.
+We have made and will continue to make expenditures to comply with environmental regulations and
+requirements. These are necessary business costs in the oil and gas industry. Although we are not
+fully insured against all environmental risks, we maintain insurance coverage which we believe is
+customary in the industry. Moreover, it is possible that other developments, such as stricter and
+more comprehensive environmental laws and regulations, as well as claims for damages to property or
+persons resulting from company operations, could result in substantial costs and liabilities, to
+Callon. We believe we are in compliance with existing environmental regulations, and that, absent
+the occurrence of an extraordinary event the effect of which cannot be predicted, any noncompliance
+will not have a material adverse effect on our operations or earnings.
+Commitments and Contingencies 
+The Company’s activities are subject to federal, state and local laws and regulations governing
+environmental quality and pollution control. Although no assurances can be made, the Company
+believes that, absent the occurrence of an extraordinary event, compliance with existing federal,
+state and local laws, rules and regulations governing the release of materials into the environment
+or otherwise relating to the protection of the environment will not have a material effect upon the
+capital expenditures, earnings or the competitive position of the Company with respect to its
+existing assets and operations. The Company cannot predict what effect additional regulation or
+legislation, enforcement polices thereunder, and claims for
+14 
+Table of Contents 
+damages to property, employees, other
+persons, and the environment resulting from the Company’s operations could have on its activities.
+Property Summary 
+We are engaged in the exploration, development, acquisition and production of oil and gas
+properties. Our properties are concentrated offshore in the Gulf of Mexico and onshore, primarily,
+in Louisiana. We have historically increased our reserves and production by focusing primarily on
+low to moderate risk exploration and acquisition opportunities in the Gulf of Mexico shelf area.
+In 1998, we expanded our area of exploration to include the Gulf of Mexico deepwater area. As of
+December 31, 2007, our estimated net proved reserves totaled 263.6 Bcfe and included 24.5 million
+barrels of oil (“MMBbls”) and 116.5 billion cubic feet of natural gas (“Bcf”), with a pre-tax
+present value, discounted at 10%, of the estimated future net revenues based on constant prices in
+effect at year-end of $1,591.5 million. Oil constitutes approximately 56% on an equivalent basis of
+our total estimated proved reserves and approximately 19% of our total estimated proved reserves
+are proved developed reserves.
+In April 2007 we acquired BP’s 80% interest in the Entrada Field which is located in the deepwater
+region of the Gulf of Mexico. We now own a 100% interest, operate and have begun development of
+the field. We currently expect first production from this deepwater discovery to be in early 2009.
+To help us fund development and achieve this production target, we have entered into an agreement
+to sell 50% of our working interest in the Entrada field to CIECO. See “Note 14 — Entrada
+Acquisition and Development” for more details.
+15 
+Table of Contents 
+Significant Properties 
+The following table shows discounted cash flows and net proved oil and gas reserves estimated by
+our independent petroleum reserve engineers by major field and for all other properties combined at
+December 31, 2007.
+Pre-tax 
+Discounted 
+Estimated Net Proved Reserves 
+Present 
+Oil 
+Gas 
+Total 
+Value 
+Operator 
+(MBbls) 
+(MMcf) 
+(MMcfe) 
+($000) 
+(a)(b)(c) 
+Gulf of Mexico Deepwater: 
+Garden Banks Block
+738/782/826/827
+“Entrada” 
+Callon 
+17,482 
+87,127 
+192,019 
+$ 
+1,144,110 
+Mississippi Canyon 538/582
+“Medusa” 
+Murphy 
+5,326 
+3,648 
+35,601 
+251,277 
+Garden Banks Block 341
+“Habanero” 
+Shell 
+1,457 
+5,681 
+14,425 
+113,015 
+Gulf of Mexico Shelf and Onshore: 
+High Island Blocks 165/130 
+StatoilHydro 
+23 
+4,320 
+4,459 
+18,851 
+East Cameron 2/LA 
+Callon 
+34 
+1,135 
+1,339 
+5,248 
+High Island Block A-540 
+Walter Oil & Gas Corp. 
+54 
+1,743 
+2,067 
+13,561 
+West Cameron Block 295 
+StatoilHydro/Cimarex 
+16 
+5,401 
+5,499 
+27,083 
+East Cameron Block 109 
+Energy Partners LTD 
+39 
+1,376 
+1,611 
+8,430 
+Other 
+Various 
+100 
+6,023 
+6,620 
+9,897 
+Total Net Proved Reserves 
+24,531 
+116,454 
+263,640 
+$ 
+1,591,472 
+(a) 
+Represents the present value of future net cash flows before deduction of federal income
+taxes, discounted at 10%, attributable to estimated net proved reserves as of December 31,
+2007, as set forth in the Company’s reserve reports prepared by its independent petroleum
+reserve engineers, Huddleston & Co., Inc. of Houston, Texas. Average pricing was $7.59 per
+Mcf for natural gas and $90.92 per Bbl for oil. 
+(b) 
+Includes a reduction for estimated plugging and abandonment costs that is reflected as a
+liability on our balance sheet at December 31, 2007, in accordance with Statement of Financial
+Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). See
+the Oil and Gas Reserve table for the standardized measure of discounted future net cash flow. 
+(c) 
+We use the financial measure “present value of estimated future net revenues from proved
+reserves, excluding income taxes.” This is a non-GAAP financial measure. We believe that
+present value of estimated future net revenues from proved reserves, excluding income taxes,
+while not a financial measure in accordance with generally accepted accounting principles, is
+an important financial measure used by investors and independent oil and gas producers for
+evaluating the relative value of oil and natural gas properties and acquisitions because the
+tax characteristics of comparable companies can differ materially. The total standardized
+measure for our proved reserves as of December 31, 2007 was $1.1 billion. The standardized
+measure gives effect to income taxes, and is calculated in accordance with Statement of
+Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities.”
+The standardized measure of our estimated net proved reserves of $1.1 billion equals the
+present value of our estimated future net revenue from proved reserves, excluding income
+taxes, of $1.6 billion, less discounted estimated future income taxes relating to such future
+net revenues of $457.5 million. 
+16 
+Table of Contents 
+Gulf of Mexico Deepwater 
+Entrada, Garden Banks Blocks 738/782/826/827 
+The Entrada discovery was drilled and delineated in 2000 with two wells and seven sidetracks on
+Garden Banks Block 782. Entrada is located in approximately 4,500 feet of water in the Gulf of
+Mexico. The Entrada Area is characterized by a northwest plunging salt ridge with multiple stacked
+amplitudes trapped against the salt and various faults. At year end 2006, we reclassified a portion
+of Entrada’s estimated net proved reserves to probable, as of December 31, 2006 due to new
+performance data from analogous deepwater reservoirs. Please refer to Note 15 of our Consolidated
+Financial Statements for further information regarding reserves.
+On April 18, 2007, we completed the acquisition of BP’s 80% working interest in the Entrada Field
+for a purchase price of $190 million. The purchase price included $150 million payable at closing
+and an additional $40 million payable after the achievement of certain production milestones. The
+purchased interests included five federal offshore blocks at Garden Banks Blocks 738, 782, 785, 826
+and 827, subject to certain depth limitations. The acquisition added 150 billion cubic feet of
+natural gas equivalent (Bcfe) to
+our proved undeveloped reserves. On December 31, 2007, we owned a 100% working interest in this
+discovery and are the operator.
+On February 11, 2008, we entered into an agreement to sell 50% of our working interest in the
+Entrada field. See “ Note 14 — Entrada Acquisition and Development” for more details.
+The Magnolia field is located on blocks adjacent to Entrada and the field and related production
+facilities are owned by Conoco/Phillips, the operator, and Devon Energy Corporation (“Devon”). In
+August 2007, we entered into a production handling agreement (“PHA”) with ConocoPhillips and Devon.
+The PHA provides for production from the Entrada Field, via a subsea tieback, to be processed
+through the Magnolia production platform.
+Work has been completed on a front-end engineering design study to tie-back Entrada to the Magnolia
+production facilities. Also, engineering work has been done and long lead items have been
+identified and orders are being placed. We have entered into a rig contact with Diamond Offshore
+Drilling, Inc. to use the Ocean Victory rig to drill and complete two development wells in the
+second half of 2008. The majority of development costs are anticipated to be incurred in 2008 and
+early 2009. First production is projected to commence in the first quarter of 2009.
+Medusa, Mississippi Canyon Blocks 538/582 
+Our Medusa deepwater discovery was announced in September 1999, after we drilled the initial test
+well in 2,235 feet of water to a total depth of 16,241 feet and encountered over 120 feet of pay in
+two intervals. Subsequent sidetrack drilling from the wellbore was used to determine the extent of
+the discovery, and a second well was drilled in the first quarter of 2000 to further delineate the
+extent of the pay intervals. We own a 15% working interest, Murphy Exploration & Production Company
+(“Murphy”), the operator, owns a 60% working interest and ENI Deepwater, LLC, owns the remaining
+25% working interest.
+In 2001, a drilling program began which included four development wells and one sidetrack. The
+program included production casing being set on six wells to provide initial production take-points
+and was completed in the first half of 2002. The construction of a floating production system,
+spar, at Medusa was completed during the second quarter of 2003. The A-1 well was completed and
+tied into the spar and commenced production in late November 2003. The remaining five wells were
+completed and
+17 
+Table of Contents 
+commenced production in 2004. Mississippi Canyon 538 #4, North Medusa, was drilled
+in 2003 and was temporarily abandoned after encountering 28 feet of net pay. The well bore was
+re-entered in the fourth quarter of 2004, sidetracked and reached an objective depth of 9,600 feet
+in January 2005. The sidetrack encountered 46 feet of net pay, was completed and commenced initial
+production in April 2005.
+During 2007 the field produced 4.5 Bcfe net to us which accounted for 24% of our total production.
+Future plans include five recompletions to produce up-hole sands and a new well and a sidetrack to
+undrained areas of the field up-dip or fault separated from existing production.
+In December 2003, we transferred our undivided 15% working interest in the spar production
+facilities to Medusa Spar LLC in exchange for cash proceeds of approximately $25 million and a 10%
+ownership interest in the LLC. A detailed discussion of this transaction is included in
+“Management’s Discussion and Analysis of Financial Condition and Results of Operations-Off-Balance
+Sheet Arrangements”.
+Habanero, Garden Banks Block 341 
+During February 1999, the initial test well on our Habanero deepwater discovery encountered over
+200 feet of net pay in two zones. Located in 2,015 feet of water, the well was drilled to a
+measured depth of 21,158 feet. We own an 11.25% working interest in the well. The well is operated
+by Shell Deepwater Development Inc., which owns a 55% working interest, with the remaining working
+interest being owned by Murphy.
+A field delineation program began in mid-year 2001, which included three sidetracks of the
+discovery well. Production casing was set on this well through the last of the sidetracks to the
+Habanero 52 oil and gas sand and the Habanero 55 gas sand. Also, a development well was drilled in
+the summer of 2003 which provides a take-point for production from the Habanero 52 oil sand. By
+means of a sub-sea completion and tie-back to an existing production facility in the area operated
+by Shell, production from the Habanero 52 oil sand commenced in late November 2003 and from the
+Habanero 55 gas sand in January 2004. In July 2004, the #2 well producing the Habanero 52 oil sand
+developed mechanical difficulties with a subsurface control valve and was shut-in resulting in a
+significant loss of production. Repairs were completed and production was restored in late
+December 2004. In addition, the #1 well producing the Habanero 55 gas sand was recompleted to the
+Habanero 55 oil sand in December 2004.
+At the time the field was developed, there was no way to know what the drive mechanism would be in
+the Habanero 52 oil sand, so the wells were drilled in a mid-dip position. It is now known that
+the Habanero 52 oil sand has strong water support requiring a well at structural crest for maximum
+recovery. A sidetrack of the #1 well was completed in the third quarter of 2007 at a structurally
+high position.
+Future plans include a sidetrack of the #2 well across a fault to drain a separate gas reservoir.
+During 2007, Habanero produced 1.6 Bcfe net to us which accounted for 9% of our total production.
+Gulf of Mexico Shelf and Onshore Louisiana 
+High Island Blocks 165/130 
+The High Island 165 #1 well was spud in the fourth quarter of 2005, reached total depth of 17,029
+feet in January 2006 and logged 140 feet of net pay in the Gyro K-1 and Rob L sands. We have
+drilled two
+18 
+Table of Contents 
+development wells, the High Island Block 130 #1 and #2 wells. Both development wells
+found pay in the Gyro K-1 sand and a deeper Gyro K-2 sand. The High Island 165 #1 well and the
+High Island 130 #1 well each produce from the Gyro K-1 sand which is nearing depletion. The High
+Island 130 #2 is producing the Gyro K-2 sand. The High Island 130 #1 well will be recompleted to
+the Rob L sand upon depletion. The High Island 165/130 field produced 2.5 Bcfe net to our interest
+in 2007. We have a 16.7% working interest in the Gyro K-1 and Rob L sands and an 11.7% interest in
+the Gyro K-1 sand. The operator of the field is StatoilHydro.
+High Island Block A-540 
+The #1 well was spud in November 2005 and reached a total depth of 9,450 feet the following month
+after logging 32 feet of net pay in the objective section. First production commenced in late
+September 2006 and during 2007 the field produced 1.5 Bcfe net to us. The company owns a 60%
+working interest and Walter Oil and Gas is the operator.
+West Cameron Block 295 
+During the third quarter of 2005, the #2 well reached a total depth of 15,775 feet and logged 150
+feet of net pay in two zones. Each zone was encountered at the predicted depth and exceeded
+anticipated thickness. The #2 well commenced production in the second quarter of 2006 and
+encountered mechanical difficulties which were corrected. Sustained production was achieved by the
+third quarter of 2006. In 2006, we drilled the #4 well, an offset to the #2 well. The #4 well
+commenced production during December 2006 in a deeper, secondary zone. After this zone is depleted
+we expect to recomplete the well in the main pay zone. Callon holds a 20.5% working interest in the
+block and StatoilHydro is the operator.
+A second prospect on this block was also drilled during 2005. The #3 well was drilled to a depth
+of 16,286 feet in December 2005 and logged 110 feet of net (94 feet true vertical depth) pay in two
+zones. The well was completed in a deeper secondary zone and will probably be recompleted to the
+main pay zone in early 2008. The well commenced production in August 2006. Callon holds a 20.5%
+working interest in the block and Cimarex Energy Company is the operator.
+During 2007, the West Cameron 295 field produced 1.5 Bcfe net to us.
+East Cameron 109 
+During 2006, an exploratory well was drilled to a vertical depth of 13,110 feet and encountered 54
+feet of net pay. The well produced 0.4 Bcfe net to us in 2007. Callon owns a 25% working interest
+and Energy Partners, LTD is the operator.
+East Cameron 2/LA 
+The State Lease 18121 #1 well was drilled to a vertical depth of 14,851 feet and encountered 20
+feet of net pay in August, 2007. The well was completed in October. First production is expected
+in the second quarter of 2008. Callon owns a 42.5% working interest and is the operator.
+19 
+Table of Contents 
+Oil and Gas Reserves 
+The following table sets forth certain information about our estimated proved reserves as reported
+by Huddleston & Co., Inc. as of the dates set forth below.
+Years Ended December 31, 
+2007 
+2006 
+2005 
+(In thousands) 
+Proved developed: 
+Oil (Bbls) 
+4,723 
+5,159 
+7,323 
+Gas (Mcf) 
+22,340 
+36,750 
+30,982 
+Mcfe 
+50,678 
+67,704 
+74,921 
+Proved undeveloped: 
+Oil (Bbls) 
+19,808 
+8,106 
+11,105 
+Gas (Mcf) 
+94,114 
+29,287 
+47,039 
+Mcfe 
+212,964 
+77,924 
+113,667 
+Total proved: 
+Oil (Bbls) 
+24,531 
+13,265 
+18,428 
+Gas (Mcf) 
+116,454 
+66,037 
+78,021 
+Mcfe 
+263,640 
+145,628 
+188,588 
+Estimated pre-tax future net cash flows (a) 
+$ 
+2,317,905 
+$ 
+775,742 
+$ 
+1,487,817 
+Pre-tax discounted present value (a) (b) 
+$ 
+1,591,472 
+$ 
+534,743 
+$ 
+1,088,714 
+Standardized measure of discounted future
+net cash flows(a) (b) 
+$ 
+1,133,989 
+$ 
+470,791 
+$ 
+837,552 
+(a) 
+Includes a reduction for estimated plugging and abandonment costs that is reflected as
+a liability on our balance sheet at December 31, 2007, in accordance with SFAS 143. 
+(b) 
+We use the financial measure “present value of estimated future net revenues from
+proved reserves, excluding income taxes.” This is a non-GAAP financial measure. We
+believe that present value of estimated future net revenues from proved reserves, excluding
+income taxes, while not a financial measure in accordance with generally accepted
+accounting principles, is an important financial measure used by investors and independent
+oil and gas producers for evaluating the relative value of oil and natural gas properties
+and acquisitions because the tax characteristics of comparable companies can differ
+materially. The total standardized measure for our proved reserves as of December 31, 2007
+was $1.1 billion. The standardized measure gives effect to income taxes, and is calculated
+in accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About
+Oil and Gas Producing Activities.” The standardized measure of our estimated net proved
+reserves of $1.1 billion equals the present value of our estimated future net revenue from
+proved reserves, excluding income taxes, of $1.6 billion, less discounted estimated future
+income taxes relating to such future net revenues of $457.5 million. Average pricing was
+$7.59 per Mcf for natural gas and $90.92 per Bbl for oil. 
+20 
+Table of Contents 
+Our independent reserve engineers, Huddleston & Co., Inc., prepared the estimates of the proved
+reserves and the future net cash flows and present value thereof attributable to such proved
+reserves. Reserves were estimated using oil and gas prices and production and development costs in
+effect on December 31 of each such year, without escalation, and were otherwise prepared in
+accordance with SEC regulations regarding disclosure of oil and gas reserve information.
+There are numerous uncertainties inherent in estimating quantities of proved reserves, including
+many factors beyond our control or the control of the reserve engineers. Reserve engineering is a
+subjective process of estimating underground accumulations of oil and gas that cannot be measured
+in an exact manner. The accuracy of any reserve or cash flow estimate is a function of the quality
+of available data and of engineering and geological interpretation and judgment. Estimates by
+different engineers often vary, sometimes significantly. In addition, physical factors, such as
+the results of drilling, testing and production subsequent to the date of an estimate, as well as
+economic factors, such as an increase or decrease in product prices that renders production of such
+reserves more or less economic, may justify revision of such estimates. Accordingly, reserve
+estimates could be different from the quantities of oil and gas that are ultimately recovered.
+We have not filed any reports with other federal agencies which contain an estimate of total proved
+net oil and gas reserves during our last fiscal year.
+Present Activities and Productive Wells 
+The following table sets forth the wells we have drilled and completed during the periods
+indicated. All such wells were drilled in the continental United States primarily in federal and
+state waters in the Gulf of Mexico.
+Years Ended December 31, 
+2007 
+2006 
+2005 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development: 
+Oil 
+1 
+0.25 
+— 
+— 
+1 
+0.15 
+Gas 
+1 
+0.12 
+2 
+0.37 
+— 
+— 
+Non-productive 
+— 
+— 
+— 
+— 
+— 
+— 
+Total 
+2 
+0.37 
+2 
+0.37 
+1 
+0.15 
+Exploration: 
+Oil 
+— 
+— 
+— 
+— 
+— 
+— 
+Gas 
+2 
+0.63 
+5 
+2.05 
+7 
+2.42 
+Non-productive 
+3 
+0.47 
+8 
+2.98 
+4 
+1.25 
+Total 
+5 
+1.10 
+13 
+5.03 
+11 
+3.67 
+21 
+Table of Contents 
+The following table sets forth our productive wells as of December 31, 2007:
+Wells 
+Gross 
+Net 
+Oil: 
+Working interest 
+9.00 
+1.41 
+Royalty interest 
+— 
+— 
+Total 
+9.00 
+1.41 
+Gas: 
+Working interest 
+24.00 
+9.25 
+Royalty interest 
+6.00 
+0.18 
+Total 
+30.00 
+9.43 
+A well is categorized as an oil well or a natural gas well based upon the ratio of oil to gas
+reserves on a Mcfe basis. However, some of our wells produce both oil and gas. At December 31,
+2007, we had no wells with multiple completions. At December 31, 2007, two gross (0.22 net)
+exploration gas wells were in progress.
+Leasehold Acreage 
+The following table shows our approximate developed and undeveloped (gross and net) leasehold
+acreage as of December 31, 2007.
+Leasehold Acreage 
+Developed 
+Undeveloped 
+Location 
+Gross 
+Net 
+Gross 
+Net 
+Louisiana 
+4,472 
+2,050 
+7,091 
+2,940 
+Texas 
+2,160 
+1,080 
+11,920 
+8,600 
+Federal waters 
+88,370 
+39,101 
+343,865 
+157,967 
+Total 
+95,002 
+42,231 
+362,876 
+169,507 
+22 
+Table of Contents 
+Major Customers 
+Our production is sold generally on month-to-month contracts at prevailing prices. The following
+table identifies customers to whom we sold a significant percentage of our total oil and gas
+production during each of the 12-month periods ended:
+December 31, 
+2007 
+2006 
+2005 
+Shell Trading Company 
+25 
+% 
+41 
+% 
+34 
+% 
+Louis Dreyfus Energy Services 
+20 
+% 
+25 
+% 
+16 
+% 
+StatoilHydro 
+13 
+% 
+— 
+— 
+Plains Marketing, L.P. 
+10 
+% 
+11 
+% 
+16 
+% 
+Walter Oil and Gas Corporation 
+8 
+% 
+— 
+— 
+Chevron Texaco Natural Gas 
+— 
+3 
+% 
+10 
+% 
+Because alternative purchasers of oil and gas are readily available, we believe that the loss of
+any of these purchasers would not result in a material adverse effect on our ability to market
+future oil and gas production.
+Title to Properties 
+We believe that the title to our oil and gas properties is good and defensible in accordance with
+standards generally accepted in the oil and gas industry, subject to such exceptions which, in our
+opinion, are not so material as to detract substantially from the use or value of such properties.
+Our properties are typically subject, in one degree or another, to one or more of the following:
+• 
+royalties and other burdens and obligations, express or implied, under oil and gas
+leases; 
+• 
+overriding royalties and other burdens created by us or our predecessors in title; 
+• 
+a variety of contractual obligations (including, in some cases, development obligations)
+arising under operating agreements, farmout agreements, production sales contracts and
+other agreements that may affect the properties or their titles; 
+• 
+back-ins and reversionary interests existing under purchase agreements and leasehold
+assignments; 
+• 
+liens that arise in the normal course of operations, such as those for unpaid taxes,
+statutory liens securing obligations to unpaid suppliers and contractors and contractual
+liens under operating agreements; 
+• 
+pooling, unitization and communitization agreements, declarations and orders; and 
+• 
+easements, restrictions, rights-of-way and other matters that commonly affect property. 
+To the extent that such burdens and obligations affect our rights to production revenues, they have
+been taken into account in calculating our net revenue interests and in estimating the size and
+value of our reserves. We believe that the burdens and obligations affecting our properties are
+conventional in the industry for properties of the kind owned by us.
+23 
+Table of Contents 
+ITEM 3. LEGAL PROCEEDINGS 
+We are a defendant in various legal proceedings and claims, which arise in the ordinary course of
+our business. We do not believe the ultimate resolution of any such actions will have a material
+affect on our financial position or results of operations.
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 
+There were no matters submitted to a vote of security holders during the fourth quarter of 2007.
+24 
+Table of Contents 
+PART II. 
+ITEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED
+STOCKHOLDER MATTERS 
+Our common stock trades on the New York Stock Exchange under the symbol “CPE”. The following table
+sets forth the high and low sale prices per share as reported for the periods indicated.
+Quarter Ended 
+High 
+Low 
+2006: 
+First quarter 
+$ 
+21.25 
+$ 
+17.01 
+Second quarter 
+21.99 
+15.12 
+Third quarter 
+19.96 
+12.54 
+Fourth quarter 
+17.44 
+12.48 
+2007: 
+First quarter 
+$ 
+15.00 
+$ 
+12.54 
+Second quarter 
+15.19 
+13.26 
+Third quarter 
+15.68 
+11.50 
+Fourth quarter 
+17.21 
+13.33 
+As of March 10, 2007 there were approximately 3,699 common stockholders of record.
+We have never paid dividends on our common stock and intend to retain our cash flow from operations
+for the future operation and development of our business. In addition, our primary credit facility
+and the terms of our outstanding subordinated debt prohibit the payment of cash dividends on our
+common stock.
+25 
+Table of Contents 
+Performance Graph 
+The following graph compares the yearly percentage change for the five years ended December 31,
+2007, in the cumulative total shareholder return on the Company’s Common Stock against the
+cumulative total return for the (i) Hemscott Industry and Market Index of SIC Group 123 (the
+“Hemscott Group Index”) consisting of independent oil and gas drilling and exploration companies
+and (ii) the New York Stock Exchange Market Index. The comparison of total return on an investment
+for each of the periods assumes that $100 was invested on December 31, 2002 in the Company, the
+Hemscott Group Index and the New York Stock Exchange Market Index, and that all dividends were
+reinvested.
+2002 
+2003 
+2004 
+2005 
+2006 
+2007 
+Callon Petroleum Company 
+$ 
+100 
+$ 
+310 
+$ 
+432 
+$ 
+527 
+$ 
+449 
+$ 
+491 
+Hemscott Group Index 
+$ 
+100 
+$ 
+131 
+$ 
+184 
+$ 
+290 
+$ 
+343 
+$ 
+539 
+NYSE Market Index 
+$ 
+100 
+$ 
+130 
+$ 
+146 
+$ 
+158 
+$ 
+186 
+$ 
+195 
+ITEM 6. SELECTED FINANCIAL DATA 
+The following table sets forth, as of the dates and for the periods indicated, selected financial
+information about us. The financial information for each of the five years in the period ended
+December 31, 2007 has been derived from our audited Consolidated Financial Statements for such
+periods. The information should be read in conjunction with “Management’s Discussion and Analysis
+of Financial Condition and Results of Operations” and the Consolidated Financial Statements and
+Notes thereto. The following information is not necessarily indicative of our future results.
+26 
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+SELECTED HISTORICAL FINANCIAL INFORMATION 
+(In thousands, except per share amounts) 
+Years Ended December 31, 
+2007 
+2006 
+2005 
+2004 
+2003 
+Statement of Operations Data: 
+Operating revenues: 
+Oil and gas sales 
+$ 
+170,768 
+$ 
+182,268 
+$ 
+141,290 
+$ 
+119,802 
+$ 
+73,697 
+Operating expenses: 
+Lease operating expenses 
+27,795 
+28,881 
+24,377 
+22,308 
+11,301 
+Depreciation, depletion and amortization 
+72,762 
+65,283 
+44,946 
+47,453 
+28,253 
+General and administrative 
+9,876 
+8,591 
+8,085 
+8,758 
+4,713 
+Accretion expense 
+3,985 
+4,960 
+3,549 
+3,400 
+2,884 
+Derivative expense 
+— 
+150 
+6,028 
+1,371 
+535 
+Total operating expenses 
+114,418 
+107,865 
+86,985 
+83,290 
+47,686 
+Income from operations 
+56,350 
+74,403 
+54,305 
+36,512 
+26,011 
+Other (income) expenses: 
+Interest expense 
+34,329 
+16,480 
+16,660 
+20,137 
+30,614 
+Other (income) 
+(1,172 
+) 
+(1,869 
+) 
+(998 
+) 
+(357 
+) 
+(444 
+) 
+Loss on early extinguishment of debt 
+— 
+— 
+— 
+3,004 
+5,573 
+Total other (income) expenses 
+33,157 
+14,611 
+15,662 
+22,784 
+35,743 
+Income (loss) before income taxes 
+23,193 
+59,792 
+38,643 
+13,728 
+(9,732 
+) 
+Income tax expense (benefit) 
+8,506 
+20,707 
+13,209 
+(6,697 
+) 
+8,432 
+Income (loss) before equity in earnings of Medusa Spar LLC
+and cumulative effect of change in accounting principle 
+14,687 
+39,085 
+25,434 
+20,425 
+(18,164 
+) 
+Equity in earnings of Medusa Spar LLC, net of tax 
+507 
+1,475 
+1,342 
+1,076 
+(8 
+) 
+Income (loss) before cumulative effect of change in
+in accounting principle 
+15,194 
+40,560 
+26,776 
+21,501 
+(18,172 
+) 
+Cumulative effect of change in accounting principle,
+net of tax 
+— 
+— 
+— 
+— 
+181 
+Net income (loss) 
+15,194 
+40,560 
+26,776 
+21,501 
+(17,991 
+) 
+Preferred stock dividends 
+— 
+— 
+318 
+1,272 
+1,277 
+Net income (loss) available to common shares 
+$ 
+15,194 
+$ 
+40,560 
+$ 
+26,458 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+27 
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+SELECTED HISTORICAL FINANCIAL INFORMATION 
+(In thousands, except per share amounts) 
+Years Ended December 31, 
+2007 
+2006 
+2005 
+2004 
+2003 
+Net income (loss) per common share: 
+Basic: 
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+0.73 
+$ 
+2.00 
+$ 
+1.43 
+$ 
+1.28 
+$ 
+(1.42 
+) 
+Cumulative effect of change in accounting principle,
+net of tax 
+— 
+— 
+— 
+— 
+.01 
+Net income (loss) available to common 
+$ 
+0.73 
+$ 
+2.00 
+$ 
+1.43 
+$ 
+1.28 
+$ 
+(1.41 
+) 
+Diluted: 
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+0.71 
+$ 
+1.90 
+$ 
+1.28 
+$ 
+1.22 
+$ 
+(1.42 
+) 
+Cumulative effect of change in accounting principle,
+net of tax 
+— 
+— 
+— 
+— 
+.01 
+Net income (loss) available to common 
+$ 
+0.71 
+$ 
+1.90 
+$ 
+1.28 
+$ 
+1.22 
+$ 
+(1.41 
+) 
+Shares used in computing net income (loss) per common share: 
+Basic 
+20,776 
+20,270 
+18,453 
+15,796 
+13,662 
+Diluted 
+21,290 
+21,363 
+20,883 
+17,678 
+13,662 
+Balance Sheet Data (end of period): 
+Oil and gas properties, net 
+$ 
+681,706 
+$ 
+547,027 
+$ 
+447,364 
+$ 
+406,690 
+$ 
+390,163 
+Total assets 
+$ 
+792,482 
+$ 
+625,527 
+$ 
+533,776 
+$ 
+457,523 
+$ 
+496,032 
+Long-term debt, less current portion 
+$ 
+392,012 
+$ 
+225,521 
+$ 
+188,813 
+$ 
+192,351 
+$ 
+214,885 
+Stockholders’ equity 
+$ 
+287,075 
+$ 
+281,363 
+$ 
+228,048 
+$ 
+198,312 
+$ 
+133,261 
+We follow the full-cost method of accounting for oil and gas properties. Under this method of
+accounting, our net capitalized costs to acquire, explore and develop oil and gas properties may
+not exceed the sum of (1) the estimated future net revenues from proved reserves at current prices
+discounted at 10% and (2) the lower of cost or market of unevaluated properties, net of tax (the
+full-cost ceiling amount). If these capitalized costs exceed the full-cost ceiling amount, the
+excess is charged to expense.
+28 
+Table of Contents 
+ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
+RESULTS OF OPERATIONS 
+The following discussion is intended to assist in an understanding of our financial condition and
+results of operations. Our consolidated financial statements and notes thereto contain detailed
+information that should be referred to in conjunction with the following discussion. See Item 8
+“Financial Statements and Supplementary Data.”
+General 
+We have been engaged in the exploration, development, acquisition and production of oil and gas
+properties since 1950. Our revenues, profitability and future growth and the carrying value of our
+oil and gas properties are substantially dependent on prevailing prices of oil and gas and our
+ability to find, develop and acquire additional oil and gas reserves that are economically
+recoverable. Our ability to maintain or increase our borrowing capacity and to obtain additional
+capital on attractive terms is also influenced by oil and gas prices.
+Significant events for the year ended December 31, 2007 included:
+• 
+the completion of the acquisition of BP’s working interest in the Entrada Field for a
+purchase price of $190 million with a cash payment of $150 million at closing; 
+• 
+the seven-year $200 million senior revolving credit facility arranged by Merrill Lynch
+Capital Corporation to finance the BP acquisition; 
+• 
+the production handling agreement entered into with ConocoPhillips and Devon Energy
+Corporation to use their Magnolia production facility located on an adjacent block to host
+production from Entrada; 
+• 
+the drilling contract entered into with Diamond Offshore Drilling, Inc. for the Ocean
+Victory drilling rig to be used to drill and complete two development wells at Entrada; 
+• 
+retaining Merrill Lynch Petrie Divestiture Advisors to assist with the search to
+identify a partner to participate in the Entrada field development and entering into an
+agreement with CIECO subsequent to December 31, 2007 to sell 50% of our working interest
+in the Entrada field; and 
+• 
+the sale of our non-core, non-operated royalty and mineral interest properties, the
+proceeds of which will be used to help develop the Entrada Field. 
+Our estimated net proved oil and gas reserves increased at December 31, 2007 to 263.6 Bcfe. This
+represents an increase of 81% from previous year-end 2006 estimated proved reserves of 145.6 Bcfe.
+Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in
+the supply of and demand for oil and gas, market uncertainty and a variety of additional factors
+beyond our control. These factors include weather conditions in the United States, the condition
+of the United States economy, the actions of the Organization of Petroleum Exporting Countries,
+governmental regulation, political stability in the Middle East and elsewhere, the foreign supply
+of crude oil and natural gas, the price of foreign imports and the availability of alternate fuel
+sources. Any substantial and extended decline in the price of crude oil or natural gas would have
+an adverse effect on our carrying value of the proved reserves, borrowing capacity, revenues,
+profitability and cash flows from operations. We use derivative financial instruments (see Note 8
+to our consolidated financial statements and Item 7A. “Quantitative and Qualitative Disclosures
+About Market Risks”) for price protection purposes on a limited amount of our future production and
+do not use these instruments for trading purposes. On a Mcfe basis, natural gas represents
+approximately 55% of budgeted 2008 production and 44% of proved reserves at year-end 2007.
+29 
+Table of Contents 
+Inflation has not had a material impact on us and is not expected to have a material impact on us
+in the future.
+Summary of Significant Accounting Policies 
+Property and Equipment. We follow the full-cost method of accounting for oil and gas properties
+whereby all costs incurred in connection with the acquisition, exploration and development of oil
+and gas reserves, including certain overhead costs, are capitalized into the “full-cost pool.” The
+amounts we capitalize into the full-cost pool are depleted (charged against earnings) using the
+unit-of-production method. The full-cost method of accounting for our proved oil and gas
+properties requires that we make estimates based on assumptions as to future events that could
+change. These estimates are described below.
+Depreciation, Depletion and Amortization (DD&A) of Oil and Gas Properties . We calculate depletion
+by using the net capitalized costs in our full-cost pool plus estimated future development costs
+(combined, the depletable base) and our estimated net proved reserve quantities. Capitalized
+costs added to the full-cost pool include the following:
+• 
+the cost of drilling and equipping productive wells, dry hole costs, acquisition costs
+of properties with proved reserves, delay rentals and other costs related to exploration
+and development of our oil and gas properties; 
+• 
+our payroll and general and administrative costs and costs related to fringe benefits
+paid to employees directly engaged in the acquisition, exploration and/or development of
+oil and gas properties as well as other directly identifiable general and administrative
+costs associated with such activities. Such capitalized costs do not include any costs
+related to our production of oil and gas or our general corporate overhead; 
+• 
+costs associated with properties that do not have proved reserves classified as
+unevaluated property costs and are excluded from the depletable base. These unevaluated
+property costs are added to the depletable base at such time as wells are completed on the
+properties, the properties are sold or we determine these costs have been impaired. Our
+determination that a property has or has not been impaired (which is discussed below)
+requires that we make assumptions about future events; 
+• 
+estimated costs to dismantle, abandon and restore properties that are capitalized to the
+full-cost pool when the related liabilities are incurred under SFAS 143; and 
+• 
+our estimates of future costs to develop proved properties are added to the full-cost
+pool for purposes of the DD&A computation. We use assumptions based on the latest
+geologic, engineering, regulatory and cost data available to us to estimate these amounts.
+However, the estimates we make are subjective and may change over time. Our estimates of
+future development costs are periodically updated as additional information becomes
+available. 
+Capitalized costs included in the full-cost pool plus estimated future development costs are
+depleted and charged against earnings using the unit-of-production method. Under this method, we
+estimate the proved reserves quantities at the beginning of each accounting period. For each Mcfe
+produced during the period, we record a depletion charge equal to the amount included in the
+depletable base (net of accumulated depreciation, depletion and amortization) divided by our
+estimated net proved reserve quantities.
+Because we use estimates and assumptions to calculate proved reserves (as discussed below) and the
+amounts included in the depletable base, our depletion rates may materially change if actual
+results differ from these estimates.
+30 
+Table of Contents 
+Ceiling Test . Under the full-cost accounting rules of the SEC, we review the carrying value of our
+proved oil and gas properties each quarter. Under these rules, capitalized costs of oil and gas
+properties, net of accumulated depreciation, depletion and amortization and deferred income taxes,
+may not exceed the present value of estimated future net cash flows from proved oil and gas
+reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of
+related tax effects (the full-cost ceiling amount). These rules generally require pricing future
+oil and gas production at the unescalated market price for oil and gas at the end of each fiscal
+quarter and require a write-down if the “ceiling” is exceeded. However, if prices recover
+sufficiently subsequent to the balance sheet date before the release of the financial statements
+then use of the subsequent pricing is allowed and no write-down would be required. Given the
+volatility of oil and gas prices, it is reasonably possible that our estimate of discounted future
+net cash flows from proved oil and gas reserves could change in the near term. If oil and gas
+prices decline significantly, even if only for a short period of time, it is possible that
+write-downs of oil and gas properties could occur in the future.
+Estimating Reserves and Present Value of Estimated Future Net Cash Flows . The estimates of
+quantities of proved oil and gas reserves and the discounted present value of estimated future net
+cash flows from such reserves at the end of each quarter are based on numerous assumptions, which
+are likely to change over time. These assumptions include:
+• 
+the prices at which we can sell our oil and gas production in the future. Oil and gas
+prices are volatile, but we are required to assume that they will not change from the
+prices in effect at the end of the quarter. In general, higher oil and gas prices will
+increase quantities of proved reserves and the present value of estimated future net cash
+flows from such reserves, while lower prices will decrease these amounts. Because our
+properties have relatively short productive lives, changes in prices will affect the
+present value of estimated future net cash flows more than the estimated quantities of oil
+and gas reserves; 
+• 
+the costs to develop and produce our reserves and the costs to dismantle our production
+facilities when reserves are depleted. These costs are likely to change over time, but we
+are required to assume that costs in effect at the end of the quarter will not change.
+Increases in costs will reduce estimated oil and gas quantities and the present value of
+estimated future net cash flows, while decreases in costs will increase such amounts.
+Because our properties have relatively short productive lives, changes in costs will affect
+the present value of estimated future net cash flows more than the estimated quantities of
+oil and gas reserves; and 
+• 
+the potential royalties payable to the Mineral Management Service. See Note 9 of our
+consolidated financial statements for a more detailed discussion. 
+In addition, the process of estimating proved oil and gas reserves requires that our independent
+and internal reserve engineers exercise judgment based on available geological, geophysical and
+technical information. We have described the risks associated with reserve estimation and the
+volatility of oil and gas prices under “Risk Factors”.
+Unproved Properties . Costs associated with properties that do not have proved reserves, including
+capitalized interest, are excluded from the depletable base. These unproved properties are
+included in the line item “Unevaluated properties excluded from amortization.” Unproved property
+costs are transferred to the depletable base when wells are completed on the properties or the
+properties are sold. In addition, we are required to determine whether our unproved properties are
+impaired and, if so, include the costs of such properties in the depletable base. We determine
+whether an unproved property should be impaired by periodically reviewing our exploration program
+on a property by property basis. This determination may require the exercise of substantial
+judgment by our management.
+31 
+Table of Contents 
+Asset Retirement Obligations. We account for asset retirement obligations in accordance with
+Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”
+(“SFAS 143”), which essentially requires entities to record the fair value of a liability for
+obligations associated with the retirement of tangible long-lived assets and the associated asset
+retirement costs. Interest is accreted on the present value of the asset retirement obligation and
+reported as accretion expense within operating expenses in the Consolidated Statements of
+Operations. See Note 10 to our Consolidated Financial Statements.
+Derivatives. We periodically use derivative financial instruments to manage oil and gas price risk
+on a limited amount of our future production and do not use these instruments for trading purposes.
+Settlement of derivative contracts are generally based on the difference between the contract
+price or prices specified in the derivative instrument and a NYMEX price or other cash or futures
+index price. Such derivatives are accounted for under Statement of Financial Accounting Standards
+No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended.
+Our derivative contracts that are accounted for as cash flow hedges under SFAS 133 are recorded at
+fair market value and the changes in fair value are recorded through other comprehensive income
+(loss), net of tax, in stockholders’ equity. The cash settlements on these contracts are recorded
+as an increase or decrease in oil and gas sales. The changes in fair value related to ineffective
+derivative contracts are recognized as derivative expense (income). The cash settlement on these
+contracts is also recorded within derivative expense (income). See Note 8 to our consolidated
+financial statements.
+Share-Based Compensation. Effective January 1, 2006, we adopted Statement of Financial Accounting
+Standard No. 123 (revised 2004), “Share-Based Payment,” (“SFAS 123R”) utilizing the modified
+prospective transition method. Prior to the adoption of SFAS 123R, we accounted for stock option
+grants in accordance with Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued
+to Employees” (the intrinsic value method) and, accordingly, recognized no compensation expense for
+stock option grants.
+Under the modified prospective transition method, SFAS 123R applies to new awards, unvested awards
+as of January 1, 2006 and awards that were outstanding on January 1, 2006 that are subsequently
+modified, repurchased or cancelled. Under the modified prospective transition method, compensation
+cost recognized in 2006 includes compensation cost for all share-based payments granted prior to,
+but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in
+accordance with the original provisions of Statement of Financial Accounting Standard No. 123
+“Accounting for Stock-Based Compensation,” (“SFAS 123”) and compensation cost for all share-based
+payments granted subsequent to January 1, 2006, based on the grant-date fair value estimated in
+accordance with the provisions of SFAS 123R. Prior periods were not restated to reflect the impact
+of adopting the new standard. SFAS 123R also requires the cash flows from tax benefits resulting
+from tax deductions in excess of compensation cost recognized for stock options exercised (excess
+tax benefits) to be classified as financing cash flows. As a result of most of our stock-based
+compensation being in the form of restricted stock, the impact of the adoption of SFAS 123R on
+income before taxes, net income and basic and diluted earnings per share for the year ended
+December 31, 2006 was immaterial. See Note 3 to our consolidated financial statements.
+32 
+Table of Contents 
+New Accounting Standards 
+In September 2006, the FASB issued Statement of Financial Accounting Standard No. 157, (“SFAS
+157”), Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring
+fair value and requires enhanced disclosures about fair value measurements. In February 2007, the
+FASB issued Statement of Financial Accounting Standard No. 159 “The Fair Value Option for Financial
+Assets and Liabilities – Including an amendment of FASB No. 115” (“SFAS 159”). SFAS 159 permits
+entities to choose to measure various financial instruments and certain other items at fair value.
+These statements become effective for us on January 1, 2008. We do not anticipate that the
+implementation of these standards will have a material effect on our consolidated financial
+statements.
+Entrada Acquisition and Development. On April 18, 2007, we completed the acquisition of BP’s 80%
+working interest in the Entrada Field for a purchase price of $190 million. The purchase price
+included $150 million payable at closing and an additional $40 million payable after the
+achievement of certain production milestones. The purchased interests included five federal
+offshore blocks at Garden Banks Blocks 738, 782, 785, 826 and 827, subject to certain depth
+limitations. As a result of the acquisition, we own a 100% working interest in the Entrada field
+and are operator. The acquisition added 150 billion cubic feet of natural gas equivalent (Bcfe) to
+our proved undeveloped reserves.
+The acquisition was recorded at fair value based on the initial purchase price of $150 million. We
+may record the additional $40 million as an additional purchase price in the future when the
+production milestones are achieved, in accordance with the terms of the agreement.
+To finance the initial $150 million payment of the purchase price, we closed on a seven-year $200
+million senior revolving credit facility arranged by Merrill Lynch Capital Corporation
+contemporaneous with the closing of the acquisition. The facility is secured by a lien on the
+Entrada properties. We borrowed the full commitment amount under the facility at closing to cover
+the required $150 million payment to BP and expenses and fees related to the transaction, and the
+balance was used to pay down our UBOC senior secured credit facility.
+In August 2007, we entered into a production handling agreement (“PHA”) with ConocoPhillips and
+Devon Energy Corporation. The PHA provides for production from the Entrada Field to be processed
+through the Magnolia production platform, which is owned by ConocoPhillips and Devon. We also
+entered into a drilling contract with Diamond Offshore Drilling, Inc for the Ocean Victory drilling
+rig to be used to drill and complete two development wells at Entrada. First production is
+expected in the first quarter of 2009.
+Subsequent to December 31, 2007, we entered into an agreement with CIECO to sell 50% of our working
+interest in the Entrada field for a purchase price of $175 million with a cash payment of $155
+million at closing and the additional $20 million payable after the achievement of certain
+production milestones. Additional contingent cash payments could be payable based on
+additional cumulative production milestones. The proceeds from this divestiture along with proceeds from the mineral
+and royalty interest divestiture will be used to fully repay the seven-year $200 million revolving
+credit facility arranged by Merrill Lynch Capital Corporation along with prepayment penalties.
+Also, CIECO has agreed to provide a non-recourse loan of $150 million to assist the financing of
+our 50% share of the $300 million estimated costs to develop the Entrada field. This transaction
+is expected to close in March 2008.
+33 
+Table of Contents 
+Liquidity and Capital Resources 
+Historically, our primary sources of capital have been cash flows from operations, borrowings from
+financial institutions and the sale of debt and equity securities. In December 2007, we completed
+the sale of certain non-core, non-operated royalty and mineral interests for $61.5 million to
+strengthen our balance sheet and provide additional liquidity for the development of our Gulf of
+Mexico deepwater fields, primarily Entrada. Net cash and cash equivalents increased by $51 million
+during 2007 to $53 million. Cash provided from operating activities during 2007 totaled $109
+million, a decrease of 19% from $135 million in 2006.
+On August 30, 2006, we closed on a four-year amended and restated senior secured credit facility
+underwritten by Union Bank of California, N.A. The borrowing base which is reviewed and
+redetermined semi-annually was $50 million at December 31, 2007. There were no borrowings under
+the credit facility at December 31, 2007; however we had a letter of credit outstanding in the
+amount of $15 million to secure a drilling rig for the development of Entrada. See Note 14. As a
+result, $35 million was available for future borrowings under the credit facility as of December
+31, 2007. See Note 7 to our Consolidated Financial Statements.
+In December 2003 and March 2004, we closed on our 9.75% senior notes due 2010 in the aggregate
+principal amount of $200 million. The net proceeds from these notes and the public offering of
+3,450,000 shares of common stock in the second quarter of 2004 were used to restructure our debt
+that was maturing in 2004 and 2005. See Note 7 to the Consolidated Financial Statements for a more
+detailed discussion of long-term debt.
+The indenture governing our 9.75% senior notes due 2010, our senior secured credit facility and our
+senior revolving credit facility contain various covenants including restrictions on additional
+indebtedness and payment of cash dividends. In addition, our senior secured credit facility
+contains covenants for maintenance of certain financial ratios. We were in compliance with these
+covenants at December 31, 2007.
+Our oil and gas reserves as estimated by Huddleston & Co., Inc. were 263.6 Bcfe of natural gas
+equivalent on December 31, 2007. Our cash flow from operations during 2007 was generated by the
+production of 18.7 Bcfe. Production of our reserves during 2008, without weather related downtime,
+is projected to provide sufficient cash flow for a modest capital expenditure program, excluding
+Entrada development, which will be funded from a non-recourse credit facility and proceeds from the
+royalty and mineral interest divestiture.
+Our current planned capital expenditures for 2008, excluding the development cost for the Entrada
+field, total $60 million and include capitalized interest and general and administrative expenses.
+The current portion of our asset retirement obligation will require an additional $11 million
+resulting in capital expenditures of $71 million for 2008. Once the CIECO loan transaction closes,
+we will re-evaluate our capital expenditure plan and consider increasing the drilling portion of
+capital expenditures. The current capital expenditure plans for 2008 include:
+• 
+the discretionary drilling of up to five exploratory and development wells; 
+• 
+lease and seismic acquisition; and 
+• 
+capitalized interest and overhead. 
+We believe that our operating cash flow and our credit facilities will be adequate to meet our
+capital, debt repayment, and operating requirements for 2008. We fund our day-to-day operating
+expenses and capital expenditures from operating cash flow, supplemented as needed by borrowings
+under our credit facilities.
+34 
+Table of Contents 
+In addition, we have sold debt and equity in both public and private offerings in the past,
+and we expect that these sources of capital will continue to be available to us in the future.
+Because of the liquidity and capital resources alternatives available to us, including internally
+generated cash flows, our management believes that our short-term and long-term liquidity is
+adequate to fund operations, including our capital spending program and repayment of maturing debt.
+With regard to the Entrada Field development, we anticipate capital expenditures of approximately
+$120 million, which are expected to be funded by the non-recourse loan from CIECO and the proceeds
+from the royalty and mineral divestiture in 2007.
+Our cash flow, both in the short and long-term, is impacted by highly volatile oil and natural gas
+prices, production levels, industry trends impacting operating expenses and our ability to continue
+to acquire or find reserves at competitive prices. Cash flow forecasts for internal use by
+management are revised monthly in response to changing market conditions and production
+projections. We may adjust capital expenditure budgets within the planned total amount in response
+to the adjusted cash flow forecasts and market trends in drilling and acquisitions costs.
+The following table describes our outstanding contractual obligations as of December 31, 2007 (in
+thousands):
+Payments due by Period 
+More 
+Contractual 
+Less Than 
+One-Three 
+Three-Five 
+Than-Five 
+Obligations 
+Total 
+One Year 
+Years 
+Years 
+Years 
+Senior Secured Credit Facility 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+9.75% Senior Notes 
+200,000 
+— 
+200,000 
+— 
+— 
+Senior Revolving Credit Facility 
+200,000 
+— 
+— 
+— 
+200,000 
+Throughput Commitments: 
+Medusa Spar LLC 
+5,696 
+2,380 
+3,316 
+— 
+— 
+Medusa Oil Pipeline 
+295 
+81 
+113 
+61 
+40 
+$ 
+405,991 
+$ 
+2,461 
+$ 
+203,429 
+$ 
+61 
+$ 
+200,040 
+Off-Balance Sheet Arrangements 
+We have a 10% ownership interest in Medusa Spar LLC (“LLC”), which is a limited liability company
+that owns a 75% undivided ownership interest in the deepwater spar production facilities at our
+Medusa Field in the Gulf of Mexico. We contributed a 15% undivided ownership interest in the
+production facility to the LLC in return for approximately $25 million in cash and a 10% ownership
+interest in the LLC. The LLC earns a tariff based upon production volume throughput from the Medusa
+area. We are obligated to process our share of production from the Medusa Field and any future
+discoveries in the area through the spar production facilities. This arrangement allows us to defer
+the cost of the spar production facility over the life of the Medusa Field. Our cash proceeds were
+used to reduce the balance outstanding under our senior secured credit facility. The LLC used the
+cash proceeds from $83.7 million of non-recourse financing and a cash contribution by one of the
+LLC owners to acquire its 75% interest in the spar. On December 31, 2007, $21.7 million of the
+financing was outstanding. The balance of Medusa Spar LLC is owned by Oceaneering International,
+Inc. and Murphy. We are accounting for our 10% ownership interest in the LLC under the equity
+method.
+35 
+Table of Contents 
+Results of Operations 
+The following table sets forth certain operating information with respect to our oil and gas
+operations for each of the three years in the period ended December 31, 2007.
+December 31, 
+2007 
+2006 
+2005 
+Production: 
+Oil (MBbls) 
+1,063 
+1,634 
+1,837 
+Gas (MMcf) 
+12,340 
+10,977 
+7,768 
+Total production (MMcfe) 
+18,718 
+20,780 
+18,787 
+Average daily production (MMcfe) 
+51.3 
+56.9 
+51.5 
+Average sales price: 
+Oil (per Bbl)(a) 
+$ 
+67.63 
+$ 
+57.33 
+$ 
+41.61 
+Gas (per Mcf) 
+$ 
+8.01 
+$ 
+8.07 
+$ 
+8.35 
+Total (per Mcfe) 
+$ 
+9.12 
+$ 
+8.77 
+$ 
+7.52 
+Oil and gas revenues (in thousands): 
+Oil revenue 
+$ 
+71,891 
+$ 
+93,665 
+$ 
+76,425 
+Gas revenue 
+98,877 
+88,603 
+64,865 
+Total 
+$ 
+170,768 
+$ 
+182,268 
+$ 
+141,290 
+Lease operating expenses (in thousands) 
+$ 
+27,795 
+$ 
+28,881 
+$ 
+24,377 
+Additional per Mcfe data: 
+Sales price 
+$ 
+9.12 
+$ 
+8.77 
+$ 
+7.52 
+Lease operating expenses 
+1.48 
+1.39 
+1.30 
+Operating margin 
+$ 
+7.64 
+$ 
+7.38 
+$ 
+6.22 
+Depletion 
+$ 
+3.89 
+$ 
+3.14 
+$ 
+2.39 
+General and administrative (net of management fees) 
+$ 
+.53 
+$ 
+.41 
+$ 
+.43 
+(a) 
+Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil: 
+Average NYMEX oil price 
+$ 
+72.33 
+$ 
+66.22 
+$ 
+56.57 
+Basis differential and quality adjustments 
+(4.08 
+) 
+(7.03 
+) 
+(8.45 
+) 
+Transportation 
+(1.15 
+) 
+(1.25 
+) 
+(1.26 
+) 
+Hedging 
+0.53 
+(0.61 
+) 
+(5.25 
+) 
+Average realized oil price 
+$ 
+67.63 
+$ 
+57.33 
+$ 
+41.61 
+36 
+Table of Contents 
+Comparison of Results of Operations for the Years Ended December 31, 2007 and 2006 
+Oil and Gas Revenues 
+Total oil and gas revenues decreased 6% from $182.3 million in 2006 to $170.8 million in 2007
+primarily due to lower oil production. Total production on an equivalent basis for 2007 decreased
+by 10% versus 2006.
+Gas production during 2007 totaled 12.3 Bcf and generated $98.9 million in revenues compared to
+11.0 Bcf and $88.6 million in revenues during the same period in 2006. Average gas prices realized
+for 2007 were $8.01 per Mcf compared to $8.07 per Mcf during the same period in 2006. The 12%
+increase in 2007 production was primarily attributable to new discoveries brought on line. The
+increase was partially offset by the sale of the Mobile Bay 952,953,955 Field in the second quarter
+of 2007, early water production from East Cameron Block 90, High Island Block 73 and North Padre
+Island Block 913 and normal and expected declines in production from our High Island Block 119 and
+Mobile Bay area fields and older properties. In addition, remedial work with wireline and coil
+tubing was performed to correct mechanical problems on the A-1 well at Medusa in the fourth quarter
+of 2006 that resulted in production being restored at a lower rate.
+Oil production during 2007 totaled 1,063,000 barrels and generated $71.9 million in revenues
+compared to 1,634,000 barrels and $93.7 million in revenues for the same period in 2006. Average
+oil prices realized in 2007 were $67.63 per barrel compared to $57.33 per barrel in 2006. The 35%
+decrease in production was primarily due to the A-1 well at Medusa having mechanical problems which
+required remedial work in the fourth quarter of 2006 and resulted in production being restored at a
+lower rate. In addition, the #1 well at Habanero became uneconomic as expected in the third
+quarter of 2007 and was sidetracked and completed as planned in an updip location in the reservoir.
+Production from the sidetrack well commenced in October 2007. See the Results of Operations table
+for a reconciliation of the realized oil prices to average NYMEX.
+Lease Operating Expenses 
+Lease operating expenses for 2007 decreased by 4% to $27.8 million compared to $28.9 million for
+the same period in 2006. The decrease was primarily due to the sale of the Mobile Bay 952,953,955
+Field effective May 1, 2007, lower throughput charges at Habanero and the shut-in of our South
+Marsh Island 261 Field, which is scheduled to be plugged and abandoned. The decrease was partially
+offset by additional operating costs associated with our new discoveries.
+Depreciation, Depletion and Amortization 
+Depreciation, depletion and amortization for 2007 and 2006 were $72.8 million and $65.3 million,
+respectively. The 11% increase was due to a higher depletion rate resulting from higher costs
+associated with our exploration and development activities in the Gulf of Mexico.
+Accretion Expense 
+Accretion expense for 2007 and 2006 of $4.0 million and $5.0 million, respectively, represents
+accretion of our asset retirement obligations. See Note 10 to the Consolidated Financial
+Statements.
+37 
+Table of Contents 
+General and Administrative 
+General and administrative expenses for 2007, net of amounts capitalized, were $9.9 million
+compared to $8.6 million in 2006. The 15% increase was a result of additions to our technical staff
+and higher compensation costs.
+Interest Expense 
+Interest expense increased to $34.3 million in 2007 compared to $16.5 million in 2006. This
+increase was due to the new debt associated with the Entrada acquisition. See Notes 7 and 14 for
+more details.
+Income Taxes 
+For 2007, income tax expense was $8.5 million compared to $20.7 million in 2006. The 59% decrease
+was primarily due to a decrease in income before income taxes arising mainly out of the reduced oil
+production and increased interest expense during the year.
+38 
+Table of Contents 
+Comparison of Results of Operations for the Years Ended December 31, 2006 and 2005 Oil and Gas Revenues 
+Total oil and gas revenues increased 29% from $141.3 million in 2005 to $182.3 million in 2006
+primarily due to higher gas production and oil pricing. Total production for 2006 increased by 11%
+versus 2005, which was impacted by downtime for inclement weather.
+Gas production during 2006 totaled 11.0 Bcf and generated $88.6 million in revenues compared to 7.8
+Bcf and $64.9 million in revenues during the same period in 2005. Average gas prices realized for
+2006 were $8.07 per Mcf compared to $8.35 per Mcf during the same period in 2005. The increase in
+production was primarily due to production from our new wells at East Cameron Block 90, North Padre
+Island Block 913, High Island Block 73, Brazos Block 405, West Cameron Block 295, High Island 165
+and West Cameron 3/LA and 2005 production being negatively impacted by inclement weather. The
+increase in production from new properties was partially offset by normal and expected declines in
+production from our Habanero, High Island Block 119 and Mobile Bay area fields and older
+properties.
+Oil production during 2006 totaled 1,634,000 barrels and generated $93.7 million in revenues
+compared to 1,837,000 barrels and $76.4 million in revenues for the same period in 2005. Average
+oil prices realized in 2006 were $57.33 per barrel compared to $41.61 per barrel in 2005. Oil
+production decreased during 2006 primarily due to a normal and expected decline at Habanero. See
+the Results of Operations table for a reconciliation of the realized oil prices to average NYMEX.
+Lease Operating Expenses 
+Lease operating expenses for 2006 increased by 18% to $28.9 million compared to $24.4 million for
+the same period in 2005. The increase was primarily due to new wells coming on line, higher costs
+for fuel and marine transportation and an increase in insurance rates for our policies which were
+renewed on April 1, 2006. In addition, we incurred approximately $1.5 million for pipeline repairs
+at our South Marsh Island Block 261 field and had downhole repairs at our Medusa field.
+Depreciation, Depletion and Amortization 
+Depreciation, depletion and amortization for 2006 and 2005 were $65.3 million and $44.9 million,
+respectively. The 45% increase was due to higher production volumes and a higher average depletion
+rate for 2006 compared to 2005. The higher depletion rate was primarily attributable to higher
+costs associated with our exploration and development activities in the Gulf of Mexico and an
+increase in estimated costs of future development activities and capitalized asset retirement costs
+associated with the future site restoration, dismantlement and abandonment activities.
+Accretion Expense 
+Accretion expense for 2006 and 2005 of $5.0 million and $3.5 million, respectively, represents
+accretion of our asset retirement obligations. The increase was due to the addition of plugging
+and abandonment obligations associated with new discoveries and an increase in plugging and
+abandonment cost estimates. See Note 10 to the Consolidated Financial Statements.
+39 
+Table of Contents 
+General and Administrative 
+General and administrative expenses for 2006, net of amounts capitalized, were $8.6 million
+compared to $8.1 million in 2005. We recognized non-cash charges of approximately $1.1 million in
+the third quarter of 2006 for the vesting of 20% of restricted shares granted in August 2006.
+General and administrative expenses for 2005 included non-cash charges of $930,000 recognized in
+the second quarter of 2005 for the accelerated vesting of performance shares pursuant to the terms
+of the plan due to deaths or disability for an executive officer and two directors of the Company.
+See Note 3 for more details.
+Interest Expense 
+Interest expense was relatively consistent in 2006 in the amount of $16.5 million compared to $16.7
+million in 2005.
+Income Taxes 
+For 2006, we had income tax expense of $20.7 million compared to $13.2 million in 2005. The 57%
+increase was primarily due to an increase in income before income taxes.
+40 
+Table of Contents 
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS 
+Commodity Price Risk 
+The Company’s revenues are derived from the sale of its crude oil and natural gas production. The
+prices for oil and gas remain extremely volatile and sometimes experience large fluctuations as a
+result of relatively small changes in supply, weather conditions, economic conditions and
+government actions. From time to time, the Company enters into derivative financial instruments to
+manage oil and gas price risk.
+The Company may utilize fixed price “swaps”, which reduce the Company’s exposure to decreases in
+commodity prices and limit the benefit the Company might otherwise have received from any increases
+in commodity prices.
+The Company may utilize price “collars” to reduce the risk of changes in oil and gas prices. Under
+these arrangements, no payments are due by either party as long as the market price is above the
+floor price and below the ceiling price set in the collar. If the price falls below the floor, the
+counter-party to the collar pays the difference to the Company, and if the price rises above the
+ceiling, the counter-party receives the difference from the Company.
+Callon may purchase “puts” which reduce the Company’s exposure to decreases in oil and gas prices
+while allowing realization of the full benefit from any increases in oil and gas prices. If the
+price falls below the floor, the counter-party pays the difference to the Company.
+The Company enters into these various agreements from time to time to reduce the effects of
+volatile oil and gas prices and does not enter into derivative transactions for speculative
+purposes. However, certain of the Company’s derivative positions may not be designated as hedges
+for accounting purposes. See Note 8 to the Consolidated Financial Statements for a description of
+the Company’s hedged position at December 31, 2007.
+Based on projected annual sales volumes for 2008 (excluding incremental production from 2007
+exploratory drilling), a 10% decline in the prices Callon receives for its crude oil and natural
+gas production would have an approximate $15 million impact on our revenues.
+Interest Rate Risk 
+The Company’s $200 million senior revolving credit facility arranged by Merrill Lynch Capital
+Corporation bears interest at a variable LIBOR-based rate. As a result, an increase in LIBOR would
+increase the interest cost associated with this facility and would have a negative impact on the
+Company’s results of operations and cash flows. As of December 31, 2007, the Company had $200
+million of borrowings outstanding under the facility and had an interest rate swap in place to
+reduce its risk associated with changes in interest rates on $25 million of this variable rate debt
+for a remaining period of three months. See Note 8 to the consolidated financial statements for a
+description of the interest rate hedge and Note 7 for the Company’s outstanding debt at December
+31, 2007.
+41 
+Table of Contents 
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+Page 
+Report of Independent Registered Public Accounting Firm 
+43 
+Consolidated Balance Sheets as of December 31, 2007
+and 2006 
+44 
+Consolidated Statements of Operations for Each of the Three Years
+in the Period Ended December 31, 2007 
+45 
+Consolidated Statements of Stockholders’ Equity
+for Each of the Three Years in the Period Ended December 31, 2007 
+46 
+Consolidated Statements of Cash Flows for Each of the Three Years
+in the Period Ended December 31, 2007 
+47 
+Notes to Consolidated Financial Statements 
+48 
+42 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm
+The Board of Directors and Stockholders of 
+Callon Petroleum Company
+We have audited the accompanying consolidated balance sheets of Callon Petroleum Company as of
+December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’
+equity and cash flows for each of the three years in the period ended December 31, 2007. These
+financial statements are the responsibility of the Company’s management. Our responsibility is to
+express an opinion on these financial statements based on our audits.
+We conducted our audits in accordance with the standards of the Public Company Accounting
+Oversight Board (United States). Those standards require that we plan and perform the audit to
+obtain reasonable assurance about whether the financial statements are free of material
+misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
+disclosures in the financial statements. An audit also includes assessing the accounting
+principles used and significant estimates made by management, as well as evaluating the overall
+financial statement presentation. We believe that our audits provide a reasonable basis for our
+opinion.
+In our opinion, the financial statements referred to above present fairly, in all material
+respects, the consolidated financial position of Callon Petroleum Company as of December 31, 2007
+and 2006, and the consolidated results of its operations and its cash flows for each of the three
+years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting
+principles.
+As discussed in Note 2 to the financial statements, in 2007 the Company changed its method of
+accounting for income taxes and in 2006 the Company changed its method of accounting for
+stock-based compensation.
+We also have audited, in accordance with the standards of the Public Company Accounting
+Oversight Board (United States), Callon Petroleum Company’s internal control over financial
+reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated
+Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our
+report dated March 13, 2008, expressed an unqualified opinion thereon.
+/s/ Ernst & Young LLP
+New Orleans, Louisiana 
+March 13, 2008
+43 
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED BALANCE SHEETS 
+(In thousands, except share data) 
+December 31, 
+2007 
+2006 
+ASSETS 
+Current assets: 
+Cash and cash equivalents 
+$ 
+53,250 
+$ 
+1,896 
+Accounts receivable 
+22,073 
+32,166 
+Restricted investments 
+100 
+4,306 
+Fair market value of derivatives 
+— 
+13,311 
+Other current assets 
+6,592 
+5,973 
+Total current assets 
+82,015 
+57,652 
+Oil and gas properties, full-cost accounting method: 
+Evaluated properties 
+1,349,904 
+1,096,907 
+Less accumulated depreciation, depletion and amortization 
+(738,374 
+) 
+(604,682 
+) 
+611,530 
+492,225 
+Unevaluated properties excluded from amortization 
+70,176 
+54,802 
+Total oil and gas properties 
+681,706 
+547,027 
+Other property and equipment, net 
+1,986 
+1,996 
+Restricted investments 
+4,525 
+1,935 
+Investment in Medusa Spar LLC 
+12,673 
+12,580 
+Other assets, net 
+9,577 
+4,337 
+Total assets 
+$ 
+792,482 
+$ 
+625,527 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued liabilities 
+$ 
+37,698 
+$ 
+46,611 
+Asset retirement obligations 
+9,810 
+14,355 
+Fair market value of derivatives 
+5,205 
+— 
+Current maturities of long-term debt 
+— 
+213 
+Total current liabilities 
+52,713 
+61,179 
+Long-term debt 
+392,012 
+225,521 
+Asset retirement obligations 
+27,027 
+26,824 
+Deferred tax liability 
+32,190 
+30,054 
+Other long-term liabilities 
+1,465 
+586 
+Total liabilities 
+505,407 
+344,164 
+Stockholders’ equity: 
+Preferred Stock, $.01 par value; 2,500,000 shares authorized; 
+— 
+— 
+Common Stock, $.01 par value; 30,000,000 shares
+authorized; 20,891,145 shares and 20,747,773 shares issued
+outstanding at December 31, 2007 and 2006, respectively 
+209 
+207 
+Capital in excess of par value 
+223,336 
+220,785 
+Other comprehensive income (loss) 
+(3,383 
+) 
+8,652 
+Retained earnings 
+66,913 
+51,719 
+Total stockholders’ equity 
+287,075 
+281,363 
+Total liabilities and stockholders’ equity 
+$ 
+792,482 
+$ 
+625,527 
+The accompanying notes are an integral part of these financial statements.
+44 
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Statements of Operations 
+For the Years Ended December 31, 2007, 2006 and 2005 
+(In thousands, except per share amounts) 
+2007 
+2006 
+2005 
+Operating revenues: 
+Oil sales 
+$ 
+71,891 
+$ 
+93,665 
+$ 
+76,425 
+Gas sales 
+98,877 
+88,603 
+64,865 
+Total operating revenues 
+170,768 
+182,268 
+141,290 
+Operating expenses: 
+Lease operating expenses 
+27,795 
+28,881 
+24,377 
+Depreciation, depletion and amortization 
+72,762 
+65,283 
+44,946 
+General and administrative 
+9,876 
+8,591 
+8,085 
+Accretion expense 
+3,985 
+4,960 
+3,549 
+Derivative expense 
+— 
+150 
+6,028 
+Total operating expenses 
+114,418 
+107,865 
+86,985 
+Income from operations 
+56,350 
+74,403 
+54,305 
+Other (income) expenses: 
+Interest expense 
+34,329 
+16,480 
+16,660 
+Other income 
+(1,172 
+) 
+(1,869 
+) 
+(998 
+) 
+Total other (income) expenses 
+33,157 
+14,611 
+15,662 
+Income before income taxes 
+23,193 
+59,792 
+38,643 
+Income tax expense 
+8,506 
+20,707 
+13,209 
+Income before equity in earnings of Medusa Spar LLC 
+14,687 
+39,085 
+25,434 
+Equity in earnings of Medusa Spar LLC, net of tax 
+507 
+1,475 
+1,342 
+Net income 
+15,194 
+40,560 
+26,776 
+Preferred stock dividends 
+— 
+— 
+318 
+Net income available to common shares 
+$ 
+15,194 
+$ 
+40,560 
+$ 
+26,458 
+Net income per common share: 
+Basic 
+$ 
+0.73 
+$ 
+2.00 
+$ 
+1.43 
+Diluted 
+$ 
+0.71 
+$ 
+1.90 
+$ 
+1.28 
+Shares used in computing net income per share amounts: 
+Basic 
+20,776 
+20,270 
+18,453 
+Diluted 
+21,290 
+21,363 
+20,883 
+The accompanying notes are an integral part of these financial statements.
+45 
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY 
+(In thousands) 
+Unearned 
+Accumulated 
+Total 
+Restricted 
+Capital in 
+Other 
+Retained 
+Stock- 
+Preferred 
+Common 
+Stock 
+Excess of 
+Comprehensive 
+Earnings 
+holders’ 
+Stock 
+Stock 
+Compensation 
+Par Value 
+Income (Loss) 
+(Deficit) 
+Equity 
+Balances, December 31, 2004 
+$ 
+6 
+$ 
+176 
+$ 
+(5,352 
+) 
+$ 
+220,664 
+$ 
+(1,883 
+) 
+$ 
+(15,299 
+) 
+$ 
+198,312 
+Comprehensive income: 
+Net income 
+— 
+— 
+— 
+— 
+— 
+26,776 
+Other comprehensive income 
+— 
+— 
+— 
+— 
+1,552 
+— 
+Total comprehensive income 
+28,328 
+Preferred stock dividend 
+— 
+— 
+— 
+— 
+— 
+(318 
+) 
+(318 
+) 
+Conversion of preferred shares
+to common stock 
+(6 
+) 
+13 
+— 
+(643 
+) 
+— 
+— 
+(636 
+) 
+Shares issued pursuant to employee
+benefit and option plan 
+— 
+1 
+— 
+(325 
+) 
+— 
+— 
+(324 
+) 
+Employee stock purchase plan 
+— 
+— 
+— 
+(33 
+) 
+— 
+— 
+(33 
+) 
+Tax benefits related to stock
+compensation plans 
+— 
+— 
+— 
+1,029 
+— 
+— 
+1,029 
+Restricted stock 
+— 
+2 
+2,018 
+(330 
+) 
+— 
+— 
+1,690 
+Warrants 
+— 
+2 
+— 
+(2 
+) 
+— 
+— 
+— 
+Balances, December 31, 2005 
+— 
+194 
+(3,334 
+) 
+220,360 
+(331 
+) 
+11,159 
+228,048 
+Comprehensive income: 
+Net income 
+— 
+— 
+— 
+— 
+— 
+40,560 
+Other comprehensive income 
+— 
+— 
+— 
+— 
+8,983 
+— 
+Total comprehensive income 
+49,543 
+Shares issued pursuant to employee
+benefit and option plan 
+— 
+2 
+— 
+(441 
+) 
+— 
+— 
+(439 
+) 
+Tax benefits related to stock
+compensation plans 
+— 
+— 
+— 
+1,356 
+— 
+— 
+1,356 
+Adoption of 123R 
+3,334 
+(3,334 
+) 
+— 
+— 
+— 
+Restricted stock 
+— 
+1 
+— 
+2,854 
+— 
+— 
+2,855 
+Warrants 
+— 
+10 
+— 
+(10 
+) 
+— 
+— 
+— 
+Balances, December 31, 2006 
+$ 
+— 
+$ 
+207 
+$ 
+— 
+$ 
+220,785 
+$ 
+8,652 
+$ 
+51,719 
+$ 
+281,363 
+Comprehensive income: 
+Net income 
+— 
+— 
+— 
+— 
+— 
+15,194 
+Other comprehensive income 
+— 
+— 
+— 
+— 
+(12,035 
+) 
+— 
+Total comprehensive income 
+3,159 
+Shares issued pursuant to employee
+benefit and option plan 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+Tax benefits related to stock
+compensation plans 
+— 
+— 
+— 
+163 
+— 
+— 
+163 
+Restricted stock 
+— 
+2 
+— 
+2,388 
+— 
+— 
+2,390 
+Balances, December 31, 2007 
+$ 
+— 
+$ 
+209 
+$ 
+— 
+$ 
+223,336 
+$ 
+(3,383 
+) 
+$ 
+66,913 
+$ 
+287,075 
+The accompanying notes are an integral part of these financial statements.
+46 
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+For the Years Ended December 31, 2007, 2006 and 2005 
+(In thousands) 
+2007 
+2006 
+2005 
+Cash flows from operating activities: 
+Net income 
+$ 
+15,194 
+$ 
+40,560 
+$ 
+26,776 
+Adjustments to reconcile net income to
+cash provided by operating activities: 
+Depreciation, depletion and amortization 
+73,677 
+65,929 
+45,657 
+Accretion expense 
+3,985 
+4,960 
+3,549 
+Amortization of deferred financing costs 
+3,009 
+2,221 
+2,062 
+Equity in earnings of Medusa Spar, LLC 
+(507 
+) 
+(1,475 
+) 
+(1,342 
+) 
+Non-cash derivative expense 
+— 
+150 
+1,635 
+Deferred income tax expense 
+8,506 
+20,707 
+13,209 
+Non-cash charge related to compensation plans 
+849 
+1,420 
+1,906 
+Excess tax benefits from share-based payment arrangements 
+(163 
+) 
+(1,449 
+) 
+— 
+Changes in current assets and liabilities: 
+Accounts receivable 
+6,658 
+(2,107 
+) 
+(11,169 
+) 
+Other current assets 
+(619 
+) 
+(3,975 
+) 
+670 
+Current liabilities 
+(2,057 
+) 
+11,311 
+(8,666 
+) 
+Change in gas balancing receivable 
+(938 
+) 
+(311 
+) 
+322 
+Change in gas balancing payable 
+889 
+133 
+(289 
+) 
+Change in other long-term liabilities 
+(10 
+) 
+(2 
+) 
+(18 
+) 
+Change in other assets, net 
+810 
+(2,588 
+) 
+(292 
+) 
+Cash provided by operating activities 
+109,283 
+135,484 
+74,010 
+Cash flows from investing activities: 
+Capital expenditures 
+(127,409 
+) 
+(167,979 
+) 
+(73,072 
+) 
+Entrada acquisition 
+(150,000 
+) 
+— 
+— 
+Proceeds from sale of mineral interests 
+60,931 
+— 
+— 
+Distribution from Medusa Spar, LLC 
+687 
+1,078 
+463 
+Cash used by investing activities 
+(215,791 
+) 
+(166,901 
+) 
+(72,609 
+) 
+Cash flows from financing activities: 
+Change in accrued liabilities to be refinanced 
+— 
+(5,000 
+) 
+5,000 
+Increases in debt 
+229,000 
+88,000 
+7,000 
+Payments on debt 
+(64,000 
+) 
+(53,000 
+) 
+(12,000 
+) 
+Deferred financing costs 
+(6,429 
+) 
+— 
+— 
+Issuance of common stock 
+— 
+— 
+2 
+Buyout of preferred stock 
+— 
+— 
+(637 
+) 
+Equity issued related to employee stock plans 
+— 
+(438 
+) 
+(573 
+) 
+Excess tax benefits from share-based payment arrangements 
+163 
+1,449 
+— 
+Capital leases 
+(872 
+) 
+(263 
+) 
+(576 
+) 
+Cash dividends on preferred stock 
+— 
+— 
+(318 
+) 
+Cash provided (used) by financing activities 
+157,862 
+30,748 
+(2,102 
+) 
+Net increase (decrease) in cash and cash equivalents 
+51,354 
+(669 
+) 
+(701 
+) 
+Cash and cash equivalents: 
+Balance, beginning of period 
+1,896 
+2,565 
+3,266 
+Balance, end of period 
+$ 
+53,250 
+$ 
+1,896 
+$ 
+2,565 
+The accompanying notes are an integral part of these financial statements.
+47 
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+1. ORGANIZATION 
+General 
+Callon Petroleum Company (“the Company” or “Callon”) was organized under the laws of the state of
+Delaware in March 1994 to serve as the surviving entity in the consolidation and combination of
+several related entities (referred to herein collectively as the “Constituent Entities”). The
+combination of the businesses and properties of the Constituent Entities with the Company was
+completed on September 16, 1994 (“Consolidation”).
+As a result of the Consolidation, all of the businesses and properties of the Constituent Entities
+are owned (directly or indirectly) by the Company. Certain registration rights were granted to the
+stockholders of certain of the Constituent Entities. See Note 9.
+The Company and its predecessors have been engaged in the acquisition, development and exploration
+of crude oil and natural gas since 1950. The Company’s properties are geographically concentrated
+in Louisiana and offshore Gulf of Mexico.
+2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 
+Principles of Consolidation and Reporting 
+The Consolidated Financial Statements include the accounts of the Company, and its subsidiary,
+Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries, namely Callon Offshore
+Production, Inc. and Mississippi Marketing, Inc. All intercompany accounts and transactions have
+been eliminated. Certain prior year amounts have been reclassified to conform to presentation in
+the current year.
+Use of Estimates 
+The preparation of financial statements in conformity with U.S. generally accepted accounting
+principles requires management to make estimates and assumptions that affect the reported amounts
+of assets and liabilities and disclosure of contingent assets and liabilities at the date of the
+financial statements and the reported amounts of revenues and expenses during the reporting period.
+Actual results could differ from those estimates.
+Asset Retirement Obligations 
+The Company accounts for asset retirement obligations in accordance with Statement of Financial
+Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), which
+essentially requires entities to record the fair value of a liability for obligations associated
+with the retirement of tangible long-lived assets and the associated asset retirement costs.
+Interest is accreted on the present value of the asset retirement obligation and reported as
+accretion expense within operating expenses in the consolidated statements of operations. See Note
+10.
+48 
+Table of Contents 
+Oil and Gas Properties 
+The Company follows the full-cost method of accounting for oil and gas properties whereby all costs
+incurred in connection with the acquisition, exploration and development of oil and gas reserves,
+including certain overhead costs, are capitalized. Such amounts include the cost of drilling and
+equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest
+capitalized on unevaluated leases, other costs related to exploration and development activities,
+and site restoration, dismantlement and abandonment costs capitalized under SFAS 143. General and
+administrative costs capitalized include salaries and related fringe benefits paid to employees
+directly engaged in the acquisition, exploration and/or development of oil and gas properties as
+well as other directly identifiable general and administrative costs associated with such
+activities. Such capitalized costs ($10.8 million in 2007, $9.6 million in 2006 and $7.1 million in
+2005) do not include any costs related to production or general corporate overhead. Costs
+associated with unevaluated properties, including capitalized interest on such costs, are excluded
+from amortization. Unevaluated property costs are transferred to evaluated property costs at such
+time as wells are completed on the properties or management determines that these costs have been
+impaired.
+Costs of oil and gas properties, including future development costs, which have proved reserves and
+properties which have been determined to be worthless, are depleted using the unit-of-production
+method based on proved reserves. If the total capitalized costs of oil and gas properties, net of
+accumulated amortization and deferred taxes relating to oil and gas properties, exceed the sum of
+(1) the estimated future net revenues from proved reserves at current prices discounted at 10% and
+(2) the lower of cost or market of unevaluated properties, net of tax effects (the full-cost
+ceiling amount), then such excess is charged to expense during the period in which the excess
+occurs. See Note 11.
+Upon the acquisition or discovery of oil and gas properties, management estimates the future net
+costs to be incurred to dismantle, abandon and restore the property using available geological,
+engineering and regulatory data. Such cost estimates are periodically updated for changes in
+conditions and requirements. In accordance with SFAS 143, such costs are capitalized to the
+full-cost pool when the related liabilities are incurred. In accordance with SEC Staff Accounting
+Bulletin No. 106, assets recorded in connection with the recognition of an asset retirement
+obligation pursuant to SFAS 143 are included as part of the costs subject to the full-cost ceiling
+limitation. The future cash outflows associated with settling the recorded asset retirement
+obligations are excluded from the computation of the present value of estimated future net revenues
+used in determining the full-cost ceiling amount.
+Property and Equipment 
+Depreciation of other property and equipment is provided using the straight-line method over
+estimated lives of three to 20 years. Depreciation of pipeline and other facilities is provided
+using the straight-line method over estimated lives of 15 to 27 years. Depreciation expense of
+$457,000, $351,000 and $355,000 relating to other property and equipment was included in general
+and administrative expenses in the Company’s consolidated statements of operations for the years
+ended December 31, 2007, 2006 and 2005, respectively. The accumulated depreciation on other
+property and equipment was $11.2 million and $10.8 million as of December 31, 2007 and 2006,
+respectively.
+49 
+Table of Contents 
+Investment in Medusa Spar LLC 
+The Company has a 10% ownership interest in Medusa Spar, LLC (“LLC”), which is a limited liability
+company that owns a 75% undivided ownership interest in the deepwater spar production facilities on
+Callon’s Medusa Field in the Gulf of Mexico. The Company contributed a 15% undivided ownership
+interest in the production facility to the LLC in return for approximately $25 million in cash and
+a 10% ownership interest in the LLC. The LLC earns a tariff based upon production volume throughput
+from the Medusa area. Callon is obligated to process its share of production from the Medusa Field
+and any future discoveries in the area through the spar production facilities. This arrangement
+allows Callon to defer the cost of the spar production facility over the life of the Medusa Field.
+The Company’s cash proceeds were used to reduce the balance outstanding under its senior secured
+credit facility. The LLC used the cash proceeds from $83.7 million of non-recourse financing and a
+cash contribution by one of the LLC owners to acquire its 75% interest in the spar. On December 31,
+2007, $21.7 million of the financing was outstanding. The balance of Medusa Spar LLC is owned by
+Oceaneering International, Inc. (NYSE:OII) and Murphy Oil Corporation (NYSE:MUR). The Company is
+accounting for its 10% ownership interest in the LLC under the equity method.
+Natural Gas Imbalances 
+The Company follows the entitlement method of accounting for its proportionate share of gas
+production on a well-by-well basis, recording a receivable to the extent that a well is in an
+“undertake” position and recording a liability to the extent that a well is in an “overtake”
+position. Gas balancing receivables were $1.7 million and $714,000 as of December 31, 2007 and
+2006, respectively. Gas balancing payables were $1.3 million and $437,000 as of December 31, 2007
+and 2006, respectively.
+Derivatives 
+The Company periodically uses derivative financial instruments to manage oil and gas price risk on
+a limited amount of its future production and does not use these instruments for trading purposes.
+Settlement of derivative contracts is generally based on the difference between the contract price
+or prices specified in the derivative instrument and a NYMEX price or other cash or futures index
+price. Such derivatives are accounted for under Statement of Financial Accounting Standards No.
+133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended.
+The Company’s derivative contracts that are accounted for as cash flow hedges under SFAS 133 are
+recorded at fair market value and the changes in fair value are recorded through other
+comprehensive income (loss), net of tax, in stockholders’ equity. The cash settlements on these
+contracts are recorded as an increase or decrease in oil and gas sales. The changes in fair value
+related to ineffective derivative contracts are recognized as derivative expense (income). The
+cash settlement on these contracts is also recorded within derivative expense (income). See Note
+8.
+50 
+Table of Contents 
+Income Taxes 
+The Company accounts for income taxes in accordance with Statement of Financial Accounting
+Standards No. 109, “Accounting for Income Taxes” (“SFAS 109”). Provisions for income taxes include
+deferred taxes resulting primarily from temporary differences due to different reporting methods
+for oil and gas properties for financial reporting purposes and income tax purposes. SFAS 109
+provides for the recognition of a deferred tax asset for net operating loss carryforwards,
+statutory depletion carryforward and tax credit carryforwards, net of a valuation allowance. The
+valuation allowance is provided for that portion of the asset for which it is deemed more likely
+than not will not be realized.
+Callon adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48 “Accounting for
+Uncertainty in Income Taxes” (“FIN 48”), effective January 1, 2007. FIN 48 clarifies the
+accounting for income taxes by prescribing the minimum recognition threshold a tax position is
+required to meet before being recognized in the financial statements. FIN 48 also provides
+guidance on derecognition, measurement, classification, interest and penalties, and disclosure.
+See Note 5.
+Stock-Based Compensation 
+Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standard No. 123
+(revised 2004), “Share-Based Payment,” (“SFAS 123R”) utilizing the modified prospective transition
+method. Prior to the adoption of SFAS 123R, the Company accounted for stock option grants in
+accordance with Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to
+Employees” (the intrinsic value method) and, accordingly, recognized no compensation expense for
+stock option grants.
+Under the modified prospective transition method, SFAS 123R applies to new awards, unvested awards
+as of January 1, 2006 and awards that were outstanding on January 1, 2006 that are subsequently
+modified, repurchased or cancelled. Under the modified prospective transition method, compensation
+cost recognized in 2007 and 2006 includes compensation cost for all share-based payments granted
+prior to, but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in
+accordance with the original provisions of Statement of Financial Accounting Standard No. 123
+“Accounting for Stock-Based Compensation,” (“SFAS 123”) and compensation cost for all share-based
+payments granted subsequent to January 1, 2006, based on the grant-date fair value estimated in
+accordance with the provisions of SFAS 123R. Prior periods were not restated to reflect the impact
+of adopting the new standard.
+SFAS 123R requires the cash flows from tax benefits resulting from tax deductions in excess of
+compensation cost recognized for stock options exercised (excess tax benefits) to be classified as
+financing cash flows. The $163,000 and $1.4 million of excess tax benefits classified as a
+financing cash inflow for the years ended December 31, 2007 and 2006, respectively would have been
+classified as an operating cash flow had the Company not adopted SFAS 123R. There were no stock
+option exercises in the year ended December 31, 2007 and no cash proceeds from the exercise of
+stock options for the year ended December 31, 2006 due to the fact that all options were exercised
+through net-share settlements. As a result of most of the Company’s stock-based compensation being
+in the form of restricted stock, the impact of the adoption of SFAS 123R on income before taxes,
+net income and basic and diluted earnings per share for the year ended December 31, 2006 was not
+significant. See Note 3.
+51 
+Table of Contents 
+Accounts Receivable 
+Accounts receivable consists primarily of accrued oil and gas production receivables. The balance
+in the reserve for doubtful accounts netted within accounts receivable was $65,000 and $66,000 at
+December 31, 2007 and 2006, respectively. There were net charge offs of $1,000 recorded against
+the reserve for doubtful accounts and no provisions to expense in the three-year period ended
+December 31, 2007.
+Major Customers 
+The Company’s production is generally sold on month-to-month contracts at prevailing prices. The
+following table identifies customers to whom it sold a significant percentage of its total oil and
+gas production during each of the years ended:
+December 31, 
+2007 
+2006 
+2005 
+Shell Trading Company 
+25 
+% 
+41 
+% 
+34 
+% 
+Louis Dreyfus Energy Services 
+20 
+% 
+25 
+% 
+16 
+% 
+StatoilHydro 
+13 
+% 
+— 
+— 
+Plains Marketing, L.P. 
+10 
+% 
+11 
+% 
+16 
+% 
+Walter Oil and Gas Corporation 
+8 
+% 
+— 
+— 
+Chevron Texaco Natural Gas 
+— 
+3 
+% 
+10 
+% 
+Because alternative purchasers of oil and gas are readily available, the Company believes that the
+loss of any of these purchasers would not result in a material adverse effect on its ability to
+market future oil and gas production.
+Statements of Cash Flows 
+The Company considers all highly liquid investments with an original maturity of three months or
+less to be cash equivalents.
+The Company paid no federal income taxes for the three years in the period ended December 31, 2007.
+During the years ended December 31, 2007, 2006 and 2005, the Company made cash payments for
+interest of $37.6 million, $20.5 million and $19.9 million, respectively.
+Fair Value of Financial Instruments 
+Fair value of cash and cash equivalents, accounts receivable and accounts payable, approximated
+book value at December 31, 2007 and 2006. The fair value of the senior revolving credit facility
+approximated book value at December 31, 2007. The senior secured credit facility and capital lease
+had no balance outstanding at December 31, 2007 and the fair value approximated book value at
+December 31, 2006. The Company’s 9.75% Senior Notes due 2010 had an estimated fair value of 94%
+and 101.5% of face value at December 31, 2007 and 2006, respectively.
+52 
+Table of Contents 
+Accounting Pronouncements 
+In September 2006, the FASB issued Statement of Financial Accounting Standard No. 157, (“SFAS
+157”), Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring
+fair value and requires enhanced disclosures about fair value measurements. In February 2007, the
+FASB issued Statement of Financial Accounting Standard No. 159 “The Fair Value Option for Financial
+Assets and Liabilities – Including an amendment of FASB No. 115” (“SFAS 159”). SFAS 159 permits
+entities to choose to measure various financial instruments and certain other items at fair value.
+These statements became effective for the Company on January 1, 2008. The Company does not
+anticipate that the implementation of these new standards will have a material effect on its
+consolidated financial statements.
+3. STOCK-BASED COMPENSATION 
+The Company has various stock plans (“Plans”) under which employees of the Company and its
+subsidiaries and non-employee members of the Board of Directors of the Company have been or may be
+granted certain stock-based compensation. For further discussion of the Plans, refer to Note 12.
+For the year ended December 31, 2007, the Company recorded stock-based compensation expense of $2.9
+million, of which $1.4 million was included in general and administrative expenses and $1.5 million
+was capitalized to oil and gas properties. For the year ended
+December 31, 2006, the Company recorded stock-based compensation
+expense of $3.5 million, of which $1.8 million was included in
+general and administrative expenses and $1.7 million was capitalized
+to oil and gas properties. Shares available for future stock option or restricted
+stock grants to employees and directors under existing plans were 436,142 at December 31, 2007.
+The following table illustrates the effect on operating results and net income per share had the
+Company accounted for stock-based compensation in accordance with SFAS 123 for the year ended
+December 31, 2005:
+Year Ended December 31, 2005 
+(In thousands, except per share data) 
+Net income available to common shares,
+as reported 
+$ 
+26,458 
+Stock-based compensation expense included
+in net income as reported, net of tax 
+1,313 
+Deduct: Total stock-based
+compensation expense under fair
+value based method, net of tax 
+(1,497 
+) 
+Pro forma net income available to
+common shares 
+$ 
+26,274 
+Basic net income per share: 
+As Reported 
+1.43 
+Pro Forma 
+1.42 
+Diluted net income per share: 
+As Reported 
+1.28 
+Pro Forma 
+1.27 
+53 
+Table of Contents 
+Stock Options 
+The Company uses the Black-Scholes option pricing model to estimate the fair value of stock option
+awards with the following weighted-average assumptions for the indicated periods.
+Years Ended 
+December 31, 
+2007 
+2006 
+2005 
+Dividend yield 
+— 
+— 
+— 
+Expected volatility 
+36.2 
+% 
+38.9 
+% 
+37.5 
+% 
+Risk-free interest rate 
+4.7 
+% 
+4.6 
+% 
+4.3 
+% 
+Expected life of option (in years) 
+5 
+5 
+5 
+Weighted-average grant-date fair value 
+$ 
+5.64 
+$ 
+7.72 
+$ 
+5.93 
+Forfeiture rate 
+2.0 
+% 
+7.5 
+% 
+— 
+The assumptions above are based on multiple factors, including historical exercise patterns of
+employees with respect to exercise and post-vesting employment termination behaviors, expected
+future exercising patterns and the historical volatility of the Company’s stock price.
+The following table represents stock option activity for the three years ended December 31, 2007:
+2007 
+2006 
+2005 
+Wtd Avg 
+Wtd Avg 
+Wtd Avg 
+Shares 
+Ex Price 
+Shares 
+Ex Price 
+Shares 
+Ex Price 
+Outstanding, beginning of year 
+740,225 
+$ 
+9.93 
+1,205,558 
+$ 
+10.11 
+1,512,599 
+$ 
+9.93 
+Granted (at market) 
+30,000 
+14.27 
+15,000 
+18.69 
+65,000 
+15.79 
+Exercised 
+— 
+— 
+(480,333 
+) 
+10.66 
+(329,441 
+) 
+10.34 
+Forfeited 
+— 
+— 
+— 
+— 
+— 
+— 
+Expired 
+(15,000 
+) 
+15.31 
+— 
+— 
+(42,600 
+) 
+10.60 
+Outstanding, end of year 
+755,225 
+$ 
+10.00 
+740,225 
+$ 
+9.93 
+1,205,558 
+$ 
+10.11 
+Exercisable, end of year 
+710,225 
+$ 
+9.57 
+695,225 
+$ 
+9.44 
+1,166,558 
+$ 
+9.88 
+Weighted-average remaining 
+Contract life: 
+Outstanding options
+at end of period 
+3.39 yrs. 
+4.06 yrs. 
+3.98 yrs. 
+Outstanding
+exercisable at end of period 
+3.08 yrs. 
+3.76 yrs. 
+3.79 yrs. 
+As of December 31, 2007, the aggregate intrinsic value of options outstanding was $5.0 million and
+the aggregate intrinsic value of options exercisable was
+$4.9 million. As of December 31, 2006, the aggregate intrinsic
+value of options outstanding was $3.9 million and the aggregate
+intrinsic value of options exercisable was $3.9 million. Total
+intrinsic value of options exercised was $4.1 million for the year
+ended December 31, 2006. At December 31, 2007, there
+was $218,000 of unrecognized compensation cost related to nonvested stock options, which is
+expected to be recognized over a weighted-average period of two years.
+54 
+Table of Contents 
+Restricted Stock 
+The Plans allow for the issuance of restricted stock awards. The unearned stock-based compensation
+related to these awards is being amortized to compensation expense on a straight-line basis over
+the requisite service period for the entire award. The compensation expense for these awards was
+determined based on the market price of our stock at the date of grant applied to the total numbers
+of shares that were anticipated to fully vest. As of December 31, 2007, there was $6.4 million of
+unrecognized compensation cost associated with these awards, which is expected to be recognized
+over a weighted average period of 2.3 years.
+The following table represents unvested restricted stock activity for the year ended December 31,
+2007:
+Weighted-Average 
+Number of 
+Grant-Date 
+Shares 
+Fair Value 
+Outstanding shares at beginning of period 
+658,800 
+$ 
+15.13 
+Granted 
+10,000 
+14.54 
+Vested 
+(181,350 
+) 
+14.99 
+Forfeited 
+— 
+— 
+Outstanding shares at end of period 
+487,450 
+$ 
+15.17 
+For the years ended December 31, 2007, 2006 and 2005 the Company recognized non-cash compensation
+expense associated with the restricted stock awards of $2.7 million, $3.4 million and $2.0 million,
+respectively. Included in 2005 was $1.0 million of accelerated vesting of performance shares
+pursuant to the terms of the plan due to the deaths or disability for an executive officer and two
+directors of the Company.
+55 
+Table of Contents 
+4. NET INCOME PER SHARE 
+Basic net income per common share was computed by dividing net income by the weighted average
+number of shares of common stock outstanding during the year. Diluted net income per common share
+was determined on a weighted average basis using common shares issued and outstanding adjusted for
+the effect of stock options and restricted stock considered common stock equivalents computed using
+the treasury stock method. Diluted net income per share for 2005 also includes the dilutive effect
+of the convertible preferred stock.
+A reconciliation of the basic and diluted net income per share computation is as follows (in
+thousands, except per share amounts):
+2007 
+2006 
+2005 
+(a) Net income available to common shares 
+$ 
+15,194 
+$ 
+40,560 
+$ 
+26,458 
+Preferred dividends assuming conversion of
+preferred stock (if dilutive) 
+— 
+— 
+318 
+(b) Net income available to common shares assum-
+ing conversion of preferred stock (if dilutive) 
+$ 
+15,194 
+$ 
+40,560 
+$ 
+26,776 
+(c) Weighted average shares outstanding 
+20,776 
+20,270 
+18,453 
+Dilutive impact of stock options 
+148 
+238 
+348 
+Dilutive impact of restricted stock 
+40 
+78 
+69 
+Dilutive impact of warrants 
+326 
+777 
+1,375 
+Convertible preferred stock (if dilutive) 
+— 
+— 
+638 
+(d) Weighted average shares outstanding for diluted net income per share 
+21,290 
+21,363 
+20,883 
+Stock options excluded due to the exercise
+price being greater than the stock price 
+75 
+28 
+1 
+Basic net income per share (a ¸ c) 
+$ 
+0.73 
+$ 
+2.00 
+$ 
+1.43 
+Diluted net income per share (b ¸ d) 
+$ 
+0.71 
+$ 
+1.90 
+$ 
+1.28 
+56 
+Table of Contents 
+5. INCOME TAXES 
+Below is an analysis of deferred income taxes as of December 31, 2007 and 2006.
+December 31, 
+2007 
+2006 
+(In thousands) 
+Deferred tax asset: 
+Federal net operating loss carryforwards 
+$ 
+58,397 
+$ 
+58,051 
+State net operating loss carryforwards 
+36,345 
+33,218 
+Statutory depletion carryforward 
+4,184 
+4,651 
+Alternative minimum tax credit carryforward 
+375 
+332 
+Asset retirement obligations 
+11,274 
+12,228 
+Other 
+3,572 
+2,443 
+Valuation allowance 
+(36,345 
+) 
+(33,218 
+) 
+Total deferred tax asset 
+77,802 
+77,705 
+Deferred tax liability: 
+Oil and gas properties 
+(109,530 
+) 
+(101,921 
+) 
+Other 
+(462 
+) 
+(5,838 
+) 
+Total deferred tax liability 
+(109,992 
+) 
+(107,759 
+) 
+Net deferred tax liability 
+$ 
+(32,190 
+) 
+$ 
+(30,054 
+) 
+If not utilized, the Company’s federal net operating loss carryforwards will expire in 2013 through
+2021. The Company’s state net operating loss carryforwards will expire in 2008 through 2021. The
+Company has very limited state taxable income as primarily all of its revenue is generated in
+federal waters not subject to state income taxes. Accordingly, the Company has established a full
+valuation allowance on the tax benefit associated with these state net operating loss carryforwards
+as the Company does not anticipate generating taxable state income in the states in which these
+carryforwards apply.
+Callon adopted FIN 48 effective January 1, 2007. The Company had no significant unrecognized tax
+benefits at the date of adoption or at December 31, 2007. Accordingly, the Company does not have
+any interest or penalties related to uncertain tax positions. However, if interest or penalties
+were to be incurred related to uncertain tax positions, such amounts would be recognized in income
+tax expense. Tax periods for years 2004 through 2007 remain open to examination by the federal and
+state taxing jurisdictions to which the Company is subject.
+57 
+Table of Contents 
+Below is a reconciliation of the reported amount of income tax expense attributable to continuing
+operations for the year to the amount of income tax expense that would result from applying
+domestic federal statutory tax rates to pretax income from continuing operations.
+Years Ended December 31, 
+2007 
+2006 
+2005 
+Income tax expense computed at the statutory
+federal income tax rate 
+35 
+% 
+35 
+% 
+35 
+% 
+Other 
+2 
+% 
+— 
+(1 
+)% 
+Effective income tax rate 
+37 
+% 
+35 
+% 
+34 
+% 
+6. OTHER COMPREHENSIVE INCOME 
+The Company’s other comprehensive income (loss) of $(12.0) million, $9.0 million and $1.6 million
+for the years ended December 31, 2007, 2006 and 2005, respectively, relates to the change in fair
+value of its derivatives. Other comprehensive income (loss) was net of income tax expense
+(benefit) of $(6.5) million, $4.7 million and $835,000 for the years ended December 31, 2007, 2006
+and 2005, respectively.
+7. LONG-TERM DEBT 
+Long-term debt consisted of the following at:
+December 31, 
+2007 
+2006 
+(In thousands) 
+Senior secured credit facility 
+$ 
+— 
+$ 
+35,000 
+9.75% Senior Notes (due 2010) net of discount 
+192,012 
+189,862 
+Senior Revolving Credit Facility (due 2014) 
+200,000 
+— 
+Capital lease 
+— 
+872 
+Total long-term debt 
+392,012 
+225,734 
+Less current portion 
+— 
+213 
+Long-term portion 
+$ 
+392,012 
+$ 
+225,521 
+Senior Secured Credit Facility . On August 30, 2006, the Company closed on a four-year amended and
+restated senior secured credit facility underwritten by Union Bank of California, N.A. (“UBOC”).
+The borrowing base which is reviewed and redetermined semi-annually was $50 million at December 31,
+2007. Borrowings under the credit facility are secured by mortgages covering the Company’s major
+producing fields. As of December 31, 2007 there were no borrowings outstanding under the facility;
+however, Callon had a letter of credit outstanding in the amount of $15 million to secure a
+drilling rig for the development of Entrada. See Note 14. As a result, $35 million was available
+for future borrowings under the credit facility as of December 31, 2007.
+58 
+Table of Contents 
+In April 2007, the UBOC senior secured credit facility was amended to allow for the senior
+revolving credit facility discussed below. See Note 14.
+The credit facility bears interest at 0% to 0.50% above a defined base rate depending on
+utilization of the borrowing base or, at the option of the Company, LIBOR plus 1.375% to 2.0% based
+on utilization of the
+borrowing base. Under the senior secured credit facility, a commitment fee of 0.25% or 0.375% per
+annum, depending on the amount of the unused portion of the borrowing base, is payable quarterly.
+The range of interest rates on the senior secured credit facility during 2007 was 6.54% to 8.75%.
+Senior Revolving Credit Facility (due 2014) . On April 18, 2007, Callon closed the Entrada
+acquisition contemporaneous with a seven-year $200 million senior revolving credit facility
+arranged by Merrill Lynch Capital Corporation, which is secured by a lien on the Entrada
+properties. Borrowings outstanding under the facility bear interest at a rate of LIBOR plus 7%.
+The Company borrowed the full commitment amount under the facility at closing to cover the required
+$150 million payment to BP Exploration and Production Company (“BP”) and expenses and fees related
+to the transaction and the balance was used to pay down the Company’s UBOC senior secured credit
+facility. See Note 14.
+9.75% Senior Notes (due 2010). In December 2003, the Company borrowed $185 million pursuant to a
+senior unsecured credit facility. The loans under the credit facility have a stated interest rate
+of 9.75% and a seven-year maturity. In conjunction with the senior unsecured notes, the Company
+issued detachable warrants to purchase 2.775 million shares of its common stock at an exercise
+price of $10 per share and an expiration date of December 2010. The warrants were valued at $10.6
+million and were treated as a discount on the debt. This senior unsecured debt matures December 8,
+2010 and has an effective interest rate of 11.4%. The Company recorded the issuance of these new
+securities at a fair value of $171 million. Deferred costs of $14 million associated with the
+notes are being amortized over the life of the notes.
+During March 2004, Callon borrowed an additional $15 million under its 9.75% senior unsecured
+credit facility bringing the total outstanding under the facility to $200 million. The net proceeds
+of approximately $14 million were primarily used to retire the remaining $10 million of 12% senior
+loans due March 31, 2005 plus a 1% call premium of $100,000. The Company recorded the issuance of
+these additional new securities at a fair value of $14 million. Deferred costs of $1 million
+associated with the notes are being amortized over the life of the notes. See Note 14.
+In March 2004, the $200 million in aggregate principal amount of loans outstanding under the 9.75%
+senior unsecured credit facility were exchanged for 9.75% Senior Notes due 2010, Series A, (“Series
+A notes”), issued pursuant to a senior indenture between Callon and American Stock Transfer & Trust
+Company dated March 15, 2004. On August 12, 2004, the Company completed an offer to exchange its 
+9.75% Senior Notes due 2010, Series B, that have been registered under the Securities Act of 1933,
+for all outstanding Series A notes.
+As of December 31, 2007, 1.617 million of the 2.775 million detachable warrants issued with the
+9.75% Senior Notes due 2010 were exercised. In addition, 265,210 of the $0.01 warrants associated
+with the 12% senior loans, which were redeemed in 2004, were exercised in June 2006.
+59 
+Table of Contents 
+Certain of the Company’s subsidiaries guarantee the Company’s obligations under the $200 million
+9.75% Senior Notes due 2010. The subsidiary guarantors are 100% owned, all of the guarantees are
+full and unconditional and joint and several, the parent company has no independent assets or
+operations and any subsidiaries of the parent company other than the subsidiary guarantors are
+minor.
+Capital Lease . In December 2001, the Company entered into a 10-year gas processing agreement
+associated with a production facility on Callon’s Mobile Block 952 Field with Hanover Compression
+Limited Partnership, which was being accounted for as a capital lease. In May 2007, the Company
+sold the Mobile Block 952 Field and retired the remainder of the capital lease.
+Restrictive Covenants . The Indenture governing our 9.75% senior notes due 2010, our senior secured
+credit facility and our senior revolving credit facility contain various covenants including
+restrictions on additional indebtedness and payment of cash dividends. In addition, our senior
+secured credit facility contains covenants for maintenance of certain financial ratios. The
+Company was in compliance with these covenants at December 31, 2007.
+8. DERIVATIVES 
+The following table summarizes derivative expense for the periods presented (in thousands):
+Years Ended December 31, 
+2007 
+2006 
+2005 
+Amortization of derivative contract premiums 
+$ 
+— 
+$ 
+150 
+$ 
+1,634 
+Change in fair value and settlements of ineffective
+derivative contracts 
+— 
+— 
+4,394 
+$ 
+— 
+$ 
+150 
+$ 
+6,028 
+The change in fair value and settlements of ineffective derivative contracts in 2005 related to
+contracts that were deemed ineffective as a result of a shortfall in production volumes due to
+downtime resulting from damages caused by Hurricanes Katrina and Rita. Cash settlements on
+effective cash flow hedges for the years ended December 31, 2007 and 2006 resulted in an increase
+in oil and gas sales of $8.1 million and $8.9 million, respectively. For the year ended December
+31, 2005, cash settlements on effective cash flow hedges resulted in a reduction in oil and gas
+sales of $10.3 million.
+60 
+Table of Contents 
+Listed in the table below are the outstanding derivative contracts as of December 31, 2007:
+Collars 
+Average 
+Average 
+Volumes per 
+Quantity 
+Floor 
+Ceiling 
+Product 
+Month 
+Type 
+Price 
+Price 
+Period 
+Oil
+30,000
+Bbls
+$65.00
+$81.50
+01/08-12/08 
+Swaps 
+Volumes per 
+Quantity 
+Average 
+Product 
+Month 
+Type 
+Price 
+Period 
+Oil
+15,000
+Bbls
+$91.00
+01/08-12/08 
+Oil
+5,000
+Bbls
+$94.65
+01/08-3/08 
+In September 2007, the Company entered into a six-month interest rate swap with UBOC. Callon will
+pay UBOC a fixed interest rate of 5.43% on a notional amount of $25,000,000 and receive the
+floating LIBOR rate. The objective of the interest rate swap is to minimize the impact of variable
+interest rates by locking into a fixed rate on a portion of the borrowings of the Merrill Lynch
+Senior Secured Credit Agreement. The fair value of this interest rate swap as of December 31, 2007
+was immaterial.
+9. COMMITMENTS AND CONTINGENCIES 
+From time to time, the Company, as part of the Consolidation and other capital transactions,
+entered into registration rights agreements whereby certain parties to the transactions are
+entitled to require the Company to register common stock of the Company owned by them with the SEC
+for sale to the public in firm commitment public offerings and generally to include shares owned by
+them, at no cost, in registration statements filed by the Company. Costs of the offering will not
+include broker’s discounts and commissions, which will be paid by the respective sellers of the
+common stock.
+The Company is involved in various claims and lawsuits incidental to its business. In the opinion
+of management, the ultimate liability thereunder, if any, will not have a material adverse effect
+on the financial position or results of operations of the Company.
+The Company’s Medusa deepwater property is eligible for royalty suspensions pursuant to the Deep
+Water Royalty Relief Act. In addition, the Company has several shallow water, deep natural gas
+properties and prospects that are eligible for royalty suspensions. However, the federal offshore
+leases covering these properties contain “price threshold” provisions for oil and gas prices.
+Under these “price threshold” provisions, if the average monthly New York Mercantile Exchange
+(NYMEX) sales price for oil or gas during a fiscal year exceeds the price threshold for oil or gas,
+respectively, then royalties on the associated production must be paid to the Minerals Management
+Service (MMS) at the rate stipulated in the lease. The price thresholds are adjusted annually by
+the implicit price deflator for the GDP. The determination of whether or not royalties are due as
+a result of the average NYMEX price exceeding the price threshold is made during the first quarter
+of the succeeding year. Any royalty payments due must be made shortly after this determination is
+made. If a royalty payment is due for all production during a year as a result of
+61 
+Table of Contents 
+exceeding the price threshold, the lessee is required to make monthly royalty payments during the
+succeeding fiscal year for the succeeding year’s production. If at the end of any year the average
+NYMEX price is below the price threshold, the lessee can apply for a refund for any associated royalties
+paid during that year and the lessee will not be required to pay royalties monthly during the
+succeeding year for the succeeding year’s production.
+The Company was required to make monthly royalty payments for 2007 deepwater oil and gas production
+and will be required to make monthly royalty payments for 2008. With regard to the shallow water,
+deep
+natural gas royalty relief, the Company was not required to make royalty payments for 2007 and will
+not be required to make royalty payments for 2008.
+In the year succeeding the year in which any of the Company’s properties became subject to
+royalties as the result of the average NYMEX price exceeding the price threshold, the portion of
+reserves attributable to potential future royalties would not be included in the year-end reserve
+report. However, if the average NYMEX prices were below the price thresholds in subsequent years,
+our reserves would be increased to reflect reserves previously attributed to future royalties. As
+a result, reported oil and gas reserves could materially increase or decrease, depending on the
+relation of price thresholds versus the average NYMEX prices. The reduction in revenues resulting
+from an obligation to pay these royalties and subsequent reduction of proved reserves could have a
+material adverse effect on the Company’s results of operations and financial condition. The
+Company’s reserve report as of December 31, 2007 excluded oil and gas reserves for Medusa that are
+subject to MMS royalties as a result of the average 2007 NYMEX prices for oil and gas exceeding the
+deepwater price thresholds. With regard to the shallow water, deep natural gas properties, there
+was no reduction in reserves for potential future royalties as of December 31, 2007 as a result of
+the average 2007 NYMEX price for gas being below the price threshold.
+The Company’s Entrada Field is governed by leases from the MMS. These leases granted royalty
+suspension without provisions for pricing thresholds for crude oil and natural gas which would
+require the Company to pay royalties to the MMS if the thresholds were exceeded by the current year
+average of NYMEX prices. The MMS has notified Callon that the exclusion of the pricing provisions
+occurred in error in the lease issuance process and was not the MMS’s intention. Congress is
+considering various bills to address this issue, and if a bill were to pass to amend the leases to
+provide thresholds for crude oil and natural gas prices, the reserves for Entrada could be subject
+to such royalties. However, the MMS stated in their correspondence to the Company that they will
+continue to honor the terms of the leases as issued unless notified otherwise. This correspondence
+applies only to Callon’s original 20% working interest in the Entrada Field, the acquired 80%
+working interest is subject to such royalties.
+The Company’s activities are subject to federal, state and local laws and regulations governing
+environmental quality and pollution control. Although no assurances can be made, the Company
+believes that, absent the occurrence of an extraordinary event, compliance with existing federal,
+state and local laws, rules and regulations governing the release of materials into the environment
+or otherwise relating to the protection of the environment will not have a material effect upon the
+capital expenditures, earnings or the competitive position of the Company with respect to its
+existing assets and operations. The Company cannot predict what effect additional regulation or
+legislation, enforcement polices thereunder, and claims for damages to property, employees, other
+persons and the environment resulting from the Company’s operations could have on its activities.
+62 
+Table of Contents 
+10. ASSET RETIREMENT OBLIGATIONS 
+The following table summarizes the activity for the Company’s asset retirement obligations:
+Years Ended December 31, 
+2007 
+2006 
+Asset retirement obligations at beginning of period 
+$ 
+41,179 
+$ 
+38,273 
+Accretion expense 
+3,985 
+4,960 
+Liabilities incurred 
+6,368 
+1,440 
+Liabilities settled 
+(19,519 
+) 
+(16,970 
+) 
+Revisions to estimate 
+4,824 
+13,476 
+Asset retirement obligation at end of period 
+36,837 
+41,179 
+Less: current retirement obligations 
+(9,810 
+) 
+(14,355 
+) 
+Long-term retirement obligations 
+$ 
+27,027 
+$ 
+26,824 
+Assets, primarily short-term U.S. Government securities, of approximately $4.6 million at December
+31, 2007, of which $100,000 was current, were recorded as restricted investments. These assets are
+held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s
+oil and gas properties.
+63 
+Table of Contents 
+11. OIL AND GAS PROPERTIES 
+The following table discloses certain financial data relating to the Company’s oil and gas
+activities, all of which are located in the United States.
+Years Ended December 31, 
+2007 
+2006 
+2005 
+(In thousands) 
+Capitalized costs incurred: 
+Evaluated Properties- 
+Beginning of period balance 
+$ 
+1,096,907 
+$ 
+937,698 
+$ 
+862,101 
+Property acquisition costs 
+154,193 
+4,053 
+6,627 
+Exploration costs 
+35,959 
+73,659 
+46,379 
+Development costs 
+62,845 
+81,497 
+22,591 
+End of period balance 
+$ 
+1,349,904 
+$ 
+1,096,907 
+$ 
+937,698 
+Unevaluated Properties (excluded from
+amortization) - 
+Beginning of period balance 
+$ 
+54,802 
+$ 
+49,065 
+$ 
+39,042 
+Additions 
+21,525 
+19,103 
+18,739 
+Capitalized interest 
+7,152 
+6,477 
+5,655 
+Transfers to evaluated 
+(13,303 
+) 
+(19,843 
+) 
+(14,371 
+) 
+End of period balance 
+$ 
+70,176 
+$ 
+54,802 
+$ 
+49,065 
+Accumulated depreciation, depletion
+and amortization- 
+Beginning of period balance 
+$ 
+604,682 
+$ 
+539,399 
+$ 
+494,453 
+Provision charged to expense 
+72,762 
+65,283 
+44,946 
+Sale of mineral interests 
+60,930 
+— 
+— 
+End of period balance 
+$ 
+738,374 
+$ 
+604,682 
+$ 
+539,399 
+Unevaluated property costs, primarily lease acquisition costs incurred at federal and state lease
+sales, unevaluated drilling costs, capitalized interest and general and administrative costs being
+excluded from the amortizable evaluated property base, consisted of $28.0 million incurred in 2007,
+$16.8 million incurred in 2006, $15.6 million incurred in 2005 and $9.8 million incurred in 2004
+and prior. These costs are directly related to the acquisition and evaluation of unproved
+properties and major development projects. The excluded costs and related reserves are included in
+the amortization base as the properties are evaluated and proved reserves are established or
+impairment is determined. The Company expects that the majority of these costs will be evaluated
+over the next three to five years.
+Depletion per unit-of-production (thousand cubic feet of gas equivalent) amounted to $3.89, $3.14
+and $2.39 for the years ended December 31, 2007, 2006, and 2005, respectively.
+Under the full-cost accounting rules of the SEC, the Company reviews the carrying value of its
+proved oil and gas properties each quarter. Under these rules, capitalized costs of oil and gas
+properties, net of accumulated depreciation, depletion and amortization and deferred income taxes,
+may not exceed the present value of estimated future net cash flows from proved oil and gas
+reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of
+related tax effects (the full-cost ceiling amount). These rules generally require pricing future
+oil and gas production at the unescalated market price for oil and gas at the end of each fiscal
+quarter and require a write-down if the “ceiling” is exceeded. However, if prices recover
+sufficiently subsequent to the balance sheet date before the release of the financial statements
+then
+64 
+Table of Contents 
+use of subsequent pricing is allowed and no write-down would be required if such pricing was used.
+Given the volatility of oil and gas prices, it is reasonably possible that the Company’s estimate
+of discounted
+future net cash flows from proved oil and gas reserves could change in the near term. If oil and
+gas prices decline significantly, even if only for a short period of time, it is possible that
+write-downs of oil and gas properties could occur in the future.
+12. EMPLOYEE BENEFIT PLANS 
+The Company has adopted a series of incentive compensation plans designed to align the interest of
+the executives and employees with those of its stockholders. The following is a brief description
+of each plan:
+Savings and Protection Plan 
+The Savings and Protection Plan (“401-K Plan”) provides employees with the
+option to defer receipt of a portion of their compensation and the Company may, at
+its discretion, match a portion of the employee’s deferral with cash and Company
+Common Stock. The Company may also elect, at its discretion, to contribute a
+non-matching amount in cash and Company Common Stock to employees. The amounts held
+under the 401-K Plan are invested in various funds maintained by a third party in
+accordance with the directions of each employee. An employee is fully vested,
+including Company discretionary contributions, immediately upon participation in the
+401-K Plan. The total amounts contributed by the Company, including the value of
+the common stock contributed, were $680,000, $615,000 and $557,000 in the years
+2007, 2006 and 2005, respectively.
+1996 Stock Incentive Plan 
+On August 23, 1996, the Board of Directors of the Company approved and adopted
+the Callon Petroleum Company 1996 Stock Incentive Plan (the “1996 Plan”). The 1996
+Plan was approved by the shareholders in 1997 and limited to a maximum of 1,200,000
+shares (as amended from the original 900,000 shares) of common stock subject to
+outstanding awards. The 1996 Plan was amended again and approved on May 9, 2000 at
+the Annual Meeting of Shareholders, increasing the number of shares reserved for
+issuance under the 1996 plan to 2,200,000 shares. Unvested options are subject to
+forfeiture upon certain termination of employment events and expire 10 years from
+the date of grant.
+In August 2006, the Board of Directors approved the award of 520,000 shares of
+restricted stock from the 1996 Plan. Of the 520,000 shares, 20,000 shares were
+granted to non-employee members of the Board of Directors and vested immediately.
+The remaining 500,000 shares were issued to employees of the Company with 20% vesting
+immediately and the remaining 80% vesting ratably over the next four years. The
+compensation cost with respect to the 20% that vested immediately was recognized as
+an expense on the grant date and the compensation cost with respect to the remaining
+80% is being amortized to expense over the vesting period.
+65 
+Table of Contents 
+2002 Stock Incentive Plan 
+On February 14, 2002, the Board of Directors of the Company approved and
+adopted the 2002 Stock Incentive Plan (the “2002 Plan”). Pursuant to the 2002 Plan,
+350,000 shares of common stock shall be reserved for issuance upon the exercise of
+options or for grants of stock options, stock appreciation rights or units, bonus
+stock, or performance shares or units. This Plan qualified as a “broadly based” plan
+under the provisions of the New York Stock Exchange’s rules and regulations and
+therefore did not require shareholder approval. Because the 2002 Plan is a broadly
+based plan, the aggregate number of shares underlying awards granted to officers and
+directors cannot exceed 50% of the total number of shares underlying the awards
+granted to all employees during any three-year period.
+In 2006, 17,500 shares were awarded as restricted stock with 20% vesting immediately
+and the remaining 80% vesting ratably over the next four years. The compensation cost
+with respect to the 20% that vested immediately was recognized as an expense on the
+grant date and the compensation cost with respect to the remaining 80% is being
+amortized to expense over the vesting period.
+2006 Stock Incentive Plan 
+On March 9, 2006, the Board of Directors of the Company approved the 2006 Stock
+Incentive Plan (“2006 Plan”). The 2006 Plan was approved by the shareholders at the
+May 4, 2006 annual meeting. Pursuant to the 2006 Plan, 500,000 shares of common
+stock shall be reserved for issuance upon exercise of stock options, restricted
+stock or other stock-based awards. In 2006, 45,000 shares were awarded as
+restricted stock that will vest ratably over the next four years. The compensation
+cost with respect to this grant is being amortized to expense over the vesting
+period.
+13. EQUITY TRANSACTIONS 
+On June 13, 2005, Callon called for redemption all of the Company’s outstanding shares of $2.125
+Convertible Exchange Preferred Stock, Series A. A notice of redemption and letter of transmittal
+was mailed to all holders of record as of the close of business on June 10, 2005. 573,108 shares
+of preferred stock were converted into 1,302,572 shares of the Company’s common stock and 23,563
+shares of the Company’s preferred stock were redeemed for $606,000 on July 14, 2005.
+The Company adopted a stockholder rights plan on March 30, 2000, designed to assure that the
+Company’s stockholders receive fair and equal treatment in the event of any proposed takeover of
+the Company and to guard against partial tender offers, squeeze-outs, open market accumulations,
+and other abusive tactics to gain control without paying all stockholders a fair price. The rights
+plan was not adopted in response to any specific takeover proposal. Under the rights plan, the
+Company declared a dividend of one right (“Right”) on each share of the Company’s Common Stock.
+Each Right will entitle the holder to purchase one one-thousandth of a share of a Series B
+Preferred Stock, par value $0.01 per share, at an exercise price of $90 per one one-thousandth of a
+share.
+The Rights are not currently exercisable and will become exercisable only in the event a person or
+group acquires, or engages in a tender or exchange offer to acquire, beneficial ownership of 15
+percent or more (one existing stockholder was granted an exception for up to 21 percent) of the
+Company’s common stock. After the Rights become exercisable, each Right will also entitle its
+holder to purchase a number of
+66 
+Table of Contents 
+common shares of the Company having a market value of twice the exercise price. The dividend
+distribution was made to stockholders of record at the close of business on April 10, 2000. The
+Rights will expire on March 30, 2010.
+14. ENTRADA ACQUISITION AND DEVELOPMENT 
+On April 18, 2007, the Company completed an acquisition of BP’s 80% working interest in the Entrada
+field for a purchase price of $190 million. The purchase price included $150 million payable at
+closing and an additional $40 million payable after the achievement of certain production
+milestones. The purchased interests included five federal offshore blocks at Garden Banks Blocks
+738, 782, 785, 826 and 827, subject to certain depth limitations. As a result of the acquisition,
+Callon owns a 100% working interest in the Entrada field and is operator. The acquisition added
+150 billion cubic feet of natural gas equivalent (Bcfe) to Callon’s proved undeveloped reserves.
+The acquisition was recorded at fair value based on the initial purchase price of $150 million.
+The Company may record the additional $40 million as additional purchase price in the future when
+the production milestones are achieved, in accordance with the terms of the agreement.
+To finance the initial $150 million payment of the purchase price, Callon closed on a seven-year
+$200 million senior revolving credit facility arranged by Merrill Lynch Capital Corporation
+contemporaneous with the closing of the acquisition. The facility is secured by a lien on the
+Entrada properties. The Company borrowed the full commitment amount under the facility at closing
+to cover the required $150 million payment to BP and expenses and fees related to the transaction
+and the balance was used to pay down our UBOC senior secured credit facility.
+In August 2007, Callon entered into a production handling agreement (“PHA”) with ConocoPhillips and
+Devon Energy Corporation. The PHA provides for production from the Entrada field to be processed
+through the Magnolia production platform, which is owned by ConocoPhillips and Devon.
+Subsequent to December 31, 2007, the Company entered into an agreement with CIECO Energy (US)
+Company (“CIECO”) to sell 50% of the Company’s working
+interest in the Entrada Field for a purchase price of $175
+million with $155 million payable at closing and the additional $20 million payable
+after the achievement of certain production milestones. Additional
+contingent cash payments could be payable based on additional
+cumulative production milestones. Also, CIECO will reimburse Callon
+for 50% of Entrada development expenditures incurred prior to the
+closing date. In addition, CIECO has
+agreed to provide a non-recourse loan of $150 million to Callon for financing of Callon’s 50% share
+of the estimated costs to develop the Entrada field. In connection with this financing, waivers
+and consents are required for the UBOC senior secured credit facility and by a majority of the
+holders of the 9.75% Senior Notes (due 2010).
+67 
+Table of Contents 
+15. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED) 
+The Company’s proved oil and gas reserves at December 31, 2007, 2006 and 2005 have been estimated
+by Huddleston & Co., Inc., the Company’s independent petroleum engineers. The reserves were
+prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve
+estimates are based upon existing economic and operating conditions.
+There are numerous uncertainties inherent in establishing quantities of proved reserves. The
+following reserve data represents estimates only and should not be construed as being exact. In
+addition, the standardized measure of discounted future net cash flows should not be construed as
+the current market value of the Company’s oil and gas properties or the cost that would be incurred
+to obtain equivalent reserves. See Note 9 regarding the provisions for royalty relief and the
+effect on reserves.
+68 
+Table of Contents 
+Estimated Reserves 
+Changes in the estimated net quantities of crude oil and natural gas reserves, all of which are
+located onshore and offshore in the continental United States, are as follows:
+Reserve Quantities 
+Years Ended December 31, 
+2007 
+2006 
+2005 
+Proved developed and undeveloped reserves: 
+Crude Oil (MBbls): 
+Beginning of period 
+13,265 
+18,428 
+19,748 
+Revisions to previous estimates 
+(1,152 
+) 
+(3,733 
+) 
+316 
+(a) 
+Change in ownership 
+144 
+— 
+— 
+Purchase of reserves in place 
+13,658 
+— 
+71 
+Sale of reserves in place 
+(356 
+) 
+— 
+— 
+Extensions and discoveries 
+35 
+204 
+129 
+Production 
+(1,063 
+) 
+(1,634 
+) 
+(1,836 
+) 
+End of period 
+24,531 
+13,265 
+18,428 
+Natural Gas (MMcf): 
+Beginning of period 
+66,037 
+78,021 
+72,619 
+Revisions to previous estimates 
+(3,022 
+) 
+(15,557 
+) 
+(4,946 
+) 
+Change in ownership 
+192 
+— 
+— 
+Purchase of reserves in place 
+68,068 
+— 
+1,308 
+Sale of reserves in place 
+(3,690 
+) 
+— 
+— 
+Extensions and discoveries 
+1,209 
+14,550 
+16,808 
+Production 
+(12,340 
+) 
+(10,977 
+) 
+(7,768 
+) 
+End of period 
+116,454 
+66,037 
+78,021 
+Proved developed reserves: 
+Crude Oil (MBbls): 
+Beginning of period 
+5,159 
+7,323 
+10,292 
+End of period 
+4,723 
+5,159 
+7,323 
+Natural Gas (MMcf): 
+Beginning of period 
+36,750 
+30,982 
+33,982 
+End of period 
+22,340 
+36,750 
+30,982 
+(a) 
+Includes Medusa royalty adjustment 
+69 
+Table of Contents 
+Standardized Measure 
+The following tables present the Company’s standardized measure of discounted future net cash flows
+and
+changes therein relating to proved oil and gas reserves and were computed using reserve valuations
+based on regulations prescribed by the SEC. These regulations provide that the oil and gas price
+structure utilized to project future net cash flows reflect period-end prices (approximately $7.59
+per Mcf for natural gas and $90.92 per Bbl for oil for the 2007 disclosures, $5.78 per Mcf and
+$54.07 per Bbl for 2006 disclosures, and $10.13 per Mcf and $55.44 per Bbl for 2005 disclosures) at
+each date presented with no escalation. Future production and development costs are based on
+current costs without escalation. The resulting net future cash flows have been discounted to
+their present values based on a 10% annual discount factor.
+Standardized Measure 
+Years Ended December 31, 
+2007 
+2006 
+2005 
+(In thousands) 
+Future cash inflows 
+$ 
+3,113,759 
+$ 
+1,101,182 
+$ 
+1,814,208 
+Future costs -
+Production 
+(390,669 
+) 
+(243,740 
+) 
+(238,321 
+) 
+Development and net abandonment 
+(405,186 
+) 
+(81,700 
+) 
+(88,070 
+) 
+Future net inflows before income taxes 
+2,317,904 
+775,742 
+1,487,817 
+Future income taxes 
+(699,967 
+) 
+(119,685 
+) 
+(379,287 
+) 
+Future net cash flows 
+1,617,937 
+656,057 
+1,108,530 
+10% discount factor 
+(483,948 
+) 
+(185,266 
+) 
+(270,978 
+) 
+Standardized measure of discounted
+future net cash flows 
+$ 
+1,133,989 
+$ 
+470,791 
+$ 
+837,552 
+Changes in Standardized Measure 
+Years Ended December 31, 
+2007 
+2006 
+2005 
+(In thousands) 
+Standardized measure – beginning of period 
+$ 
+470,791 
+$ 
+837,552 
+$ 
+515,893 
+Sales and transfers, net of production costs 
+(142,973 
+) 
+(153,387 
+) 
+(116,913 
+) 
+Net change in sales and transfer prices,
+net of production costs 
+411,525 
+(347,193 
+) 
+391,570 
+Net change due to purchases and sales of in
+place reserves 
+795,595 
+— 
+— 
+Extensions, discoveries, and improved
+recovery, net of future production and
+development costs incurred 
+(201,750 
+) 
+122,862 
+127,848 
+Revisions of quantity estimates 
+(66,735 
+) 
+(155,342 
+) 
+(17,241 
+) 
+Accretion of discount 
+53,474 
+108,871 
+61,259 
+Net change in income taxes 
+(393,530 
+) 
+187,209 
+(154,460 
+) 
+Changes in production rates, timing and other 
+207,592 
+(129,781 
+) 
+29,596 
+Aggregate change 
+663,198 
+(366,761 
+) 
+321,659 
+Standardized measure — end of period 
+$ 
+1,133,989 
+$ 
+470,791 
+$ 
+837,552 
+At year-end 2006, a downward revision was made by the Company’s independent petroleum engineers to
+Entrada’s estimated net proved reserves as of December 31, 2006 due to new performance data from
+analogous deepwater reservoirs.
+70 
+Table of Contents 
+16. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) 
+First 
+Second 
+Third 
+Fourth 
+Quarter 
+Quarter 
+Quarter 
+Quarter 
+2007 
+(In thousands, except per share data) 
+Total revenues 
+$ 
+45,484 
+$ 
+43,474 
+$ 
+37,869 
+$ 
+43,941 
+Income from operations 
+13,705 
+12,828 
+13,090 
+16,727 
+Net income 
+5,803 
+2,581 
+2,268 
+4,542 
+Net income per common share-basic 
+$ 
+0.28 
+$ 
+0.12 
+$ 
+0.11 
+$ 
+0.22 
+Net income per common share-diluted 
+0.27 
+0.12 
+0.11 
+0.21 
+First 
+Second 
+Third 
+Fourth 
+Quarter 
+Quarter 
+Quarter 
+Quarter 
+2006 
+(In thousands, except per share data) 
+Total revenues 
+$ 
+45,581 
+$ 
+47,057 
+$ 
+44,878 
+$ 
+44,752 
+Income from operations 
+22,605 
+21,616 
+17,815 
+12,367 
+Net income 
+12,767 
+12,303 
+9,630 
+5,860 
+Net income per common share-basic 
+$ 
+0.66 
+$ 
+0.61 
+$ 
+0.47 
+$ 
+0.28 
+Net income per common share-diluted 
+0.60 
+0.57 
+0.45 
+0.27 
+71 
+Table of Contents 
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+There have been no disagreements with the independent auditors on any matters of accounting
+principles or practices, financial statement disclosure, or auditing scope or procedures.
+ITEM 9.A CONTROLS AND PROCEDURES 
+The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the
+Securities Exchange Act of 1934, or the Exchange Act. This term refers to the controls and
+procedures of a company that are designed to ensure that information required to be disclosed by a
+company in the reports that it files or submits under the Exchange Act is recorded, processed,
+summarized and reported within the time periods specified by the Securities and Exchange
+Commission. Our management, including our Chief Executive Officer and Chief Financial Officer, has
+evaluated the effectiveness of our disclosure controls and procedures as of the end of the period
+covered by this annual report. Based upon that evaluation, our Chief Executive Officer and Chief
+Financial Officer have concluded that our disclosure controls and procedures were effective as of
+the end of the period covered by this annual report. There were no changes to our internal control
+over financial reporting during our last fiscal quarter that have materially affected, or are
+reasonable likely to materially affect, our internal control over financial reporting.
+Management’s Report On Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over
+financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the
+supervision and with the participation of our management, including our principal executive and
+financial officers, we conducted an evaluation of the effectiveness of our internal control over
+financial reporting as of December 31, 2007 based on the frame work in the Internal
+Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
+Commission. Based on our evaluation under the framework in Internal Control-Integrated Framework,
+our management concluded that our internal control over financial reporting was effective as of
+December 31, 2007.
+Ernst & Young LLP, our independent registered public accounting firm, has issued an attestation
+report on the Company’s internal control over financial reporting as of December 31, 2007.
+72 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm
+The Board
+of Directors and Stockholders of 
+Callon Petroleum Company
+We have audited Callon Petroleum Company’s internal control over financial reporting as of December
+31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the
+Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Callon
+Petroleum Company’s management is responsible for maintaining effective internal control over
+financial reporting and for its assessment of the effectiveness of internal control over financial
+reporting included in the accompanying Management’s Report on Internal Control over Financial
+Reporting. Our responsibility is to express an opinion on the Company’s internal control over
+financial reporting based on our audit.
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
+Board (United States). Those standards require that we plan and perform the audit to obtain
+reasonable assurance about whether effective internal control over financial reporting was
+maintained in all material respects. Our audit included obtaining an understanding of internal
+control over financial reporting, assessing the risk that a material weakness exists, testing and
+evaluating the design and operating effectiveness of internal control based on the assessed risk,
+and performing such other procedures as we considered necessary in the circumstances. We believe
+that our audit provides a reasonable basis for our opinion.
+A company’s internal control over financial reporting is a process designed to provide reasonable
+assurance regarding the reliability of financial reporting and the preparation of financial
+statements for external purposes in accordance with generally accepted accounting principles. A
+company’s internal control over financial reporting includes those policies and procedures that (1)
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
+transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
+transactions are recorded as necessary to permit preparation of financial statements in accordance
+with generally accepted accounting principles, and that receipts and expenditures of the company
+are being made only in accordance with authorizations of management and directors of the company;
+and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
+acquisition, use, or disposition of the company’s assets that could have a material effect on the
+financial statements.
+Because of its inherent limitations, internal control over financial reporting may not prevent or
+detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
+subject to the risk that controls may become inadequate because of changes in conditions, or that
+the degree of compliance with the policies or procedures may deteriorate.
+In our opinion, Callon Petroleum Company maintained, in all material respects, effective internal
+control over financial reporting as of December 31, 2007, based on the COSO criteria.
+73 
+Table of Contents 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight
+Board (United States), the consolidated balance sheets of Callon Petroleum Company as of December
+31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity and
+cash flows for each of the three years in the period ended December 31, 2007 and our report dated March 13, 2008, expressed an unqualified opinion thereon.
+/s/ Ernst & Young LLP 
+New Orleans, Louisiana 
+March 13, 2008
+74 
+Table of Contents 
+ITEM 9.B OTHER INFORMATION 
+We have disclosed all information required to be disclosed in a current report on Form 8-K during
+the fourth quarter of the year ended December 31, 2007 in previously filed reports on Form 8-K.
+75 
+Table of Contents 
+PART III. 
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. 
+For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders to be held on May 1, 2008 which will be filed with
+the Securities and Exchange Commission and is incorporated herein by reference.
+The Company has adopted a code of ethics that applies to the Company’s chief executive officer,
+chief financial officer and chief accounting officer. The full text of such code of ethics has
+been posted on the Company’s website at www.callon.com, and is available free of charge in print to
+any shareholder who requests it. Request for copies should be addressed to the Secretary at 200
+North Canal Street, Natchez, Mississippi 39120.
+ITEM 11. EXECUTIVE COMPENSATION. 
+For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders to be held on May 1, 2008 which will be filed with
+the Securities and Exchange Commission and is incorporated herein by reference.
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
+STOCKHOLDER MATTERS. 
+For information concerning the security ownership of certain beneficial owners and management, see
+the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of
+Stockholders to be held on May 1, 2008 which will be filed with the Securities and Exchange
+Commission and is incorporated herein by reference.
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders to be held on May 1, 2008 which will be filed with
+the Securities and Exchange Commission and is incorporated herein by reference.
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES. 
+For information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders to be held on May 1, 2008 which will be filed with
+the Securities and Exchange Commission and is incorporated herein by reference.
+76 
+Table of Contents 
+PART IV. 
+ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 
+(a) 1. The following is an index to the financial statements and financial statement schedules
+that are filed as part of this Form 10-K on pages 43 through 71.
+Report of Independent Registered Public Accounting Firm
+Consolidated Balance Sheets as of the Years Ended December 31, 2007 and 2006
+Consolidated Statements of Operations for the Three Years in the Period Ended
+December 31, 2007
+Consolidated Statements of Stockholders’ Equity for the Three Years in the Period Ended
+December 31, 2007
+Consolidated Statements of Cash Flows for the Three Years in the Period Ended
+December 31, 2007
+Notes to Consolidated Financial Statements
+(a) 2. Schedules other than those listed above are omitted because they are not required, not
+applicable or the required information is included in the financial statements or notes thereto.
+(a) 3. Exhibits:
+2. 
+Plan of acquisition, reorganization, arrangement, liquidation or succession* 
+3. 
+Articles of Incorporation and Bylaws 
+3.1 
+Certificate of Incorporation of the Company, as amended (incorporated by
+reference to Exhibit 3.1 of the Company’s Annual Report on Form 10-K for the year
+ended December 31, 2003, File No. 001-14039) 
+3.2 
+Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the
+Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg. No.
+33-82408) 
+3.3 
+Certificate of Amendment to Certificate of Incorporation of the Company
+(incorporated by reference to Exhibit 3.3 of the Company’s Annual Report on Form
+10-K for the year ended December 31, 2003, File No. 001-14039) 
+4. 
+Instruments defining the rights of security holders, including indentures 
+4.1 
+Specimen Common Stock Certificate (incorporated by reference from Exhibit
+4.1 of the Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg.
+No. 33-82408) 
+4.2 
+Rights Agreement between Callon Petroleum Company and American Stock Transfer
+& Trust Company, Rights Agent, dated March 30, 2000 (incorporated by reference from
+Exhibit 
+77 
+Table of Contents 
+99.1 of the Company’s Registration Statement on Form 8-A, filed April 6, 2000,
+File No. 001-14039)
+4.3 
+Form of Warrants dated December 8, 2003 and December 29, 2003 entitling lenders under
+the Company’s $185 million amended and restated senior unsecured credit agreement dated
+December 23, 2003 to purchase common stock from the Company
+(incorporated by reference to Exhibit 4.14 of the Company’s Annual Report on Form 10-K for the year
+ended December 31, 2003, File No. 001-14039) 
+4.4 
+Indenture for the Company’s 9.75% Senior Notes due 2010, dated March 15, 2004 between
+Callon Petroleum Company and American Stock Transfer and Trust Company (incorporated by
+reference to Exhibit 4.16 of the Company’s Quarterly Report on Form 10-Q for the period
+ended March 31, 2004, File No. 001-14039) 
+9. 
+Voting trust agreement 
+None.
+10. 
+Material contracts 
+10.1 
+Registration Rights Agreement dated September 16, 1994 between the Company
+and NOCO Enterprises, L. P. (incorporated by reference from Exhibit 10.2 of the
+Company’s Registration Statement on Form 8-B filed October 3,
+1994) 
+10.2 
+Counterpart to Registration Rights Agreement by and between the Company,
+Ganger Rolf ASA and Bonheur ASA. (incorporated by reference from Exhibit 10.2
+of the Company’s Report on Form 10-K for the fiscal year ended December 31,
+2000, File No. 001-14039) 
+10.3 
+Registration Rights Agreement dated September 16, 1994 between the Company
+and Callon Stockholders (incorporated by reference from Exhibit 10.3 of the Company’s
+Registration Statement on Form 8-B filed October 3, 1994) 
+10.4 
+Callon Petroleum Company 1994 Stock Incentive Plan (incorporated by
+reference from Exhibit 10.5 of the Company’s Registration Statement on Form 8-B filed
+October 3, 1994 
+10.5 
+Callon Petroleum Company 1996 Stock Incentive Plan as amended on May 9, 2000
+(incorporated by reference from Appendix I of the Company’s Definitive
+Proxy Statement of Schedule 14A filed March 28, 2000) 
+10.6 
+Conveyance of Overriding Royalty Interest from the Company to Duke Capital
+Partners, LLC, dated June 29, 2001 (incorporated by reference to Exhibit 10.03 of the
+Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2001, File No.
+001-14039) 
+10.7 
+Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference to
+Exhibit 10.13 of the Company’s Annual Report on Form 10-K for the year ended December 31,
+2001, File No. 001-14039) 
+78 
+Table of Contents 
+10.8 
+Change of Control Severance Compensation Agreement by and between Callon Petroleum
+Company and Fred L. Callon, dated January 1, 2002 (incorporated by reference to
+Exhibit 10.15 of the Company’s Annual Report on Form 10-K for the year
+ended December 31, 2001, File No. 001-14039) 
+10.9 
+Medusa Spar Agreement dated as of August 8, 2003, among Callon Petroleum Operating
+Company, Murphy Exploration & Production Company-USA and Oceaneering
+International, Inc. (incorporated by reference to Exhibit 10.19 of the Company’s
+Annual Report on Form 10-K for the year ended December 31, 2003, File No.
+001-14039) 
+10.10 
+Credit Agreement dated as of December 18, 2003 among Medusa Spar LLC, The Bank of
+Nova Scotia, as Administrative Agent, Bank One, N.A., Sun Trust Bank, as
+Syndication Agents and other Lenders Party. (incorporated by reference to
+Exhibit 10.20 of the Company’s Annual Report on Form 10-K for
+the year ended December 31, 2003, File No. 001-14039) 
+10.11 
+Amended and Restated Credit Agreement dated as of August 30, 2006 between the Company
+and Union Bank of California, N.A., as Administrative Agent (incorporated by
+reference to Exhibit 10.11 of the Company’s Current Report on Form 8-K dated
+August 31, 2006, File No. 001-14039) 
+10.12 
+Purchase and Sale Agreement executed on March 8, 2007 by
+and between Callon Petroleum Operating Company and BP Exploration
+and Production Company (incorporated by reference to Exhibit 2.1
+of the Company’s Report on Form 8-K filed on March 9, 2007). 
+10.13 
+Credit Agreement dated as of April 18, 2007 by
+and among Callon Petroleum Company, each of the “Lenders”
+signatory thereto, Merrill Lynch, Pierce, Fenner & Smith
+Incorporated, as Lead Arranger, Merrill Lynch Capital Corporation
+as Administrative Agent for the Lenders and as Revolving Loan
+Lender, and Merrill Lynch Bank USA as Deposit Bank (incorporated
+by reference from Exhibit 10.1 of the Company’s Report on Form
+8-K filed on April 24, 2007). 
+10.14 
+Amendment No. 1 dated as of April 18, 2007 among
+Callon Petroleum Company, the “Lenders” party to the Credit
+Agreement described therein, and Union Bank of California, N.A.
+as administrative agent for such Lenders (incorporated by
+reference from Exhibit 10.2 of the Company’s Report on Form 8-K
+filed on April 24, 2007). 
+10.15 
+Deepwater Production Handling and Operating
+Services Agreement for Garden Banks Blocks 738, 782, 785, 826 and
+827 Production Handling at the Garden Banks Block 783 Magnolia
+TLP, dated as of August 31, 2007, by and between ConocoPhillips
+Company and Devon Energy Production Company, L.P. and Callon
+Petroleum Operating Company (incorporated by reference from
+Exhibit 10.1 of the Company’s Report on Form 10-Q filed on
+November 6, 2007). 
+10.16 
+Purchase and Sale Agreement between Callon
+Petroleum Company and Callon Petroleum Operating Company as
+Seller, and Indigo Minerals LLC, as Buyer (incorporated by
+reference from Exhibit 2.1 of the Company’s Report on Form 8-K
+filed on December 13, 2007). 
+10.17 
+Purchase and Sale Agreement by and between Callon
+Petroleum Operating Company and CIECO Energy (US) Limited
+(incorporated by reference from Exhibit 1.1 of the Company’s
+Report on Form 8-K filed on February 13, 2008). 
+11. 
+Statement re computation of per share earnings* 
+12. 
+Statements re computation of ratios* 
+13. 
+Annual Report to security holders, Form 10-Q or quarterly reports* 
+14. 
+Code of Ethics 
+14.1 
+Code of Ethics for Chief Executive Officers and Senior Financial Officers
+(incorporated by reference to Exhibit 14.1 of the Company’s Annual Report
+on Form 10-K for the year ended December 31, 2003, File No. 001-14039) 
+16. 
+Letter re change in certifying accountant* 
+18. 
+Letter re change in accounting principles* 
+21. 
+Subsidiaries of the Company 
+21.1 
+Subsidiaries of the Company (incorporated by reference from Exhibit 21.1 of
+the Company’s Registration Statement on Form 8-B filed October 3, 1994) 
+22. 
+Published report regarding matters submitted to vote of security holders* 
+23. 
+Consents of experts and counsel 
+23.1 
+Consent of Ernst & Young LLP 
+79 
+Table of Contents 
+23.2 
+Consent of Huddleston & Co., Inc. 
+24. 
+Power of attorney* 
+31. 
+Rule 13a-14(a) Certifications 
+31.1 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) 
+31.2 
+Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) 
+32. 
+Section 1350 Certifications 
+32.1 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(b) 
+32.2 
+Certification of Chief Financial Officer pursuant to Rule 13(a)-14(b) 
+99. 
+Additional Exhibits* 
+* 
+Inapplicable to this filing. 
+80 
+Table of Contents 
+SIGNATURES 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed
+below by the following persons on behalf of the registrant and in the capacities and on the dates
+indicated.
+CALLON PETROLEUM COMPANY
+Date:
+March 17, 2008
+/s/ Fred L. Callon
+Fred L. Callon (principal executive officer, director) 
+Date:
+March 17, 2008
+/s/ B. F. Weatherly 
+B. F. Weatherly (principal financial officer, director) 
+Date:
+March 17, 2008
+/s/ Rodger W. Smith 
+Rodger W. Smith (principal accounting officer) 
+Date:
+March 17, 2008
+/s/ Richard L. Flury 
+Richard Flury (director) 
+Date:
+March 17, 2008
+/s/ John C. Wallace 
+John C. Wallace (director) 
+Date:
+March 17, 2008
+/s/ Richard O. Wilson 
+Richard O. Wilson (director) 
+Date:
+March 17, 2008
+/s/ Larry D. McVay 
+Larry McVay (director) 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
+registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
+duly authorized.
+CALLON PETROLEUM COMPANY 
+Date: March 17, 2008
+By:
+/s/ B. F. Weatherly 
+B. F. Weatherly, Executive Vice-President and
+Chief Financial Officer 
+81
\ No newline at end of file
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diff --git a/raw/filings/0000928022/2007/0000950134-08-004915/item1.txt b/raw/filings/0000928022/2007/0000950134-08-004915/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..eecf7bfe5a559a7c129d7b12d2cc1ebfffa7dcf1
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+++ b/raw/filings/0000928022/2007/0000950134-08-004915/item1.txt
@@ -0,0 +1,4849 @@
+ITEM 1 and 2. BUSINESS and PROPERTIES 
+Overview 
+Callon Petroleum Company has been engaged in the exploration, development, acquisition and
+production of oil and gas properties since 1950. Our properties are geographically concentrated
+primarily offshore in the Gulf of Mexico and onshore in Louisiana. We were incorporated under the
+laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited
+partnership, a joint venture with a consortium of European investors and an independent energy
+company owned by a member of current management. As used herein, the “Company,” “Callon,” “we,”
+“us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the
+context requires otherwise.
+In 1989, we began increasing our reserves through the acquisition of producing properties that were
+geologically complex, had (or were analogous to fields with) an established production history from
+stacked pay zones and were candidates for exploitation. We focused on reducing operating costs and
+implementing production enhancements through the application of technologically advanced production
+and recompletion techniques.
+Over the past 12 years, we have placed emphasis on the acquisition of acreage with exploration and
+development drilling opportunities in the Gulf of Mexico shelf and deepwater areas. At December
+31, 2007, we owned working interests in a total of 104 blocks/leases covering 212,000 net acres.
+To minimize risk we join with industry partners to explore federal offshore blocks acquired in the
+Gulf of Mexico. We perform extensive geological and geophysical studies using computer-aided
+exploration techniques (CAEX), including, where appropriate, the acquisition of 3-D seismic or
+high-resolution 2-D data to facilitate these efforts. We continue to develop prospects on the
+shelf through our 3-D seismic partnership using Amplitude versus Offset (“AVO”) technology. We
+have approximately 20,000 square miles of 3-D seismic data and have invested in pre-stack time
+migration in order to apply AVO de-risking to our prospects. In 1998, we began exploration in the
+Gulf of Mexico deepwater area (generally 900 to 5,500 feet of water) and during the fourth quarter
+of 2003, our first two deepwater projects, the Medusa and Habanero fields, began production. In
+April, 2007 we acquired from BP Exploration and Production Company (“BP”) their 80% interest in the
+Entrada field which is located in the deepwater region of the Gulf of Mexico. We now own a 100%
+interest, operate and have begun development of the field. Expected production from this deepwater
+discovery is currently projected to be in early 2009. Please see “Significant Properties” for a
+more detailed discussion.
+On February 11, 2008, we entered into an agreement to sell 50% of our working interest in the
+Entrada Field to CIECO Energy (US) Company (“CIECO”) effective January 1, 2008 for a purchase price
+of $175 million with a cash payment of $155 million due at closing and the additional $20 million
+payable after the achievement of certain production milestones.
+Additional contingent cash payments could be payable based on
+additional cumulative production milestones. Also, CIECO has agreed to finance our
+50% share of the estimated $300 million development costs for the Entrada field. Please see “Note
+14 — Entrada Acquisition and Development” for more details.
+We ended the year 2007 with estimated net proved reserves of 263.6 billion cubic feet of natural
+gas equivalent (“Bcfe”). This represents an increase of 81% from 2006 year-end estimated net
+proved reserves of 145.6 Bcfe.
+The major focus of our future operations is expected to continue to be the exploration for and
+development of oil and gas properties, primarily in the Gulf of Mexico.
+2 
+Table of Contents 
+Availability of Reports 
+All of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
+8-K, and amendments to such reports as well as other filings we make pursuant to Section 13(a) and
+15(d) of the Securities Exchange Act of 1934 are available free of charge on our Internet website.
+The address of our Internet website is www.callon.com. Our Securities and Exchange Commission
+(“SEC”) filings are available on our website as soon as they are posted to the EDGAR database on
+the SEC’s website.
+Business Strategy 
+Our goal is to increase shareholder value by increasing our reserves, production, cash flow and
+earnings. We seek to achieve these goals through the following strategies:
+• 
+focus on Gulf of Mexico exploration with a balance between shelf and deepwater areas,
+and onshore Louisiana; 
+• 
+aggressively explore our existing prospect inventory; 
+• 
+replenish our prospect inventory with increasing emphasis on prospect generation using
+AVO technology to reduce the risks associated with our exploratory drilling; and 
+• 
+acquire producing properties with infrastructure in areas of focus that contain upside
+potential. 
+Exploration and Development Activities 
+In 2007, capital expenditures for exploration and development costs related to oil and gas
+properties totaled approximately $124 million. These expenditures included:
+• 
+$37 million in the Gulf of Mexico shelf, onshore south Louisiana and Texas state waters
+areas which included the drilling of six exploratory wells, two of which were unsuccessful
+and two of which were in progress at the end of 2007. In addition, the $37 million
+included the cost of one development well and completion costs for our successful wells; 
+• 
+$33 million in our deepwater area, excluding our Entrada discovery, which included one
+exploratory well, Bob North which was dry, and one development well at our Habanero field; 
+• 
+$16 million on long-lead items and engineering for our Entrada discovery; 
+• 
+$17 million for leasehold and seismic costs; 
+• 
+$3 million for plugging and abandonment costs; and 
+• 
+$7 million for capitalized interest and $11 million for capitalized general and
+administration costs allocable directly to exploration and development projects. 
+Acquisitions and Divestitures 
+In April 2007, we acquired BP’s 80% working interest in the deepwater Gulf of Mexico discovery,
+Entrada, for a purchase price of $190 million, which included $150 million payable at closing and
+an additional $40 million payable after the achievement of certain production milestones. To
+strengthen our balance sheet and provide additional liquidity for the development of our Gulf of
+Mexico deepwater fields, primarily Entrada, we completed the sale of certain non-core, non-operated
+royalty and mineral interests for $61.5 million in December 2007.
+Subsequent to December 31, 2007, we entered into an agreement to sell 50% of our working interest
+in the Entrada field to CIECO for a purchase price of $175 million with a cash payment of $155
+million at
+3 
+Table of Contents 
+closing and the additional $20 million payable after the achievement of certain
+production milestones. Additional contingent cash payments could be payable based on
+additional cumulative production milestones. Please see “Note 14 — Entrada Acquisition and Development” for more
+details.
+Risk Factors 
+A decrease in oil and gas prices may adversely affect our results of operations and financial
+condition . Our success is highly dependent on prices for oil and gas, which are extremely volatile.
+Any substantial or extended decline in the price of oil or gas would have a material adverse effect
+on us. Oil and gas markets are both seasonal and cyclical. The prices of oil and gas depend on
+factors we cannot control such as weather, economic conditions, and levels of production, actions
+by OPEC and other countries and government actions. Prices of oil and gas will affect the following
+aspects of our business:
+• 
+our revenues, cash flows and earnings; 
+• 
+the amount of oil and gas that we are economically able to produce; 
+• 
+our ability to attract capital to finance our operations and the cost of the capital; 
+• 
+the amount we are allowed to borrow under our senior secured credit facility; 
+• 
+the value of our oil and gas properties; and 
+• 
+the profit or loss we incur in exploring for and developing our reserves. 
+Our reserve information represents estimates that may turn out to be incorrect if the assumptions
+upon which these estimates are based are inaccurate. Any material inaccuracies in these reserve
+estimates or underlying assumptions will materially affect the quantities and present value of our
+reserves. The process of estimating oil and gas reserves is complex. It requires interpretations
+of available technical data and various assumptions, including assumptions relating to economic
+factors. Any significant inaccuracies in these interpretations or assumptions could materially
+affect the estimated quantities and present value of reserves shown in this annual report.
+In order to prepare these estimates, we must project production rates and the timing of development
+expenditures. The assumptions regarding the timing and costs to commence production from our
+deepwater wells used in preparing our reserves are often subject to revisions over time as
+described under “Our deepwater operations have special operational risks that may negatively affect
+the value of those assets.” We must also analyze available geological, geophysical, production and
+engineering data, the extent, quality and reliability of which can vary. The process also requires
+us to make economic assumptions, such as oil and gas prices, drilling and operating expenses,
+capital expenditures, taxes and availability of funds. Therefore, estimates of oil and gas
+reserves are inherently imprecise.
+Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating
+expenses and quantities of recoverable oil and gas reserves most likely will vary from the
+estimates. Any significant variance could materially affect the estimated quantities and present
+value of reserves shown in this report. In addition, estimates of proved reserves may be adjusted
+to reflect production history, results of exploration and development, prevailing oil and gas
+prices and other factors, many of which are beyond our control.
+Also, under Mineral Management Services (“MMS”) rules governing our deepwater Medusa property and
+several of our shallow water, deep natural gas properties and prospects, we are eligible for
+royalty suspensions depending on the difference between the average monthly New York Mercantile
+Exchange (NYMEX) sales price for oil or gas and price thresholds set by the MMS. As a result, our
+reserve estimates may increase or decrease depending upon the relation of price thresholds versus
+the average NYMEX prices.
+4 
+Table of Contents 
+Our Entrada field is governed by leases from the MMS. These leases granted royalty suspension
+without provisions for pricing thresholds for crude oil and natural gas which would require us to
+pay royalties to the MMS if the thresholds were exceeded by the current year average of NYMEX
+prices. The MMS has
+notified us that the exclusion of the provisions for the pricing threshold occurred in error in the
+lease issuance process and was not the MMS’s intention. Congress is considering various bills to
+address this issue, and if a bill were to pass to amend the leases to provide thresholds for crude
+oil and natural gas prices, the reserves for Entrada could be subject to royalties. However, the
+MMS stated in their correspondence to us they will continue to honor the terms of the leases as
+issued unless notified otherwise. This correspondence applies only to our original 20% working
+interest in the Entrada Field.
+You should not assume that the present value of future net cash flows from our proved reserves
+referred to in this report is the current market value of our estimated oil and gas reserves. In
+accordance with SEC requirements, we generally base the estimated discounted future net cash flows
+from our proved reserves on prices and costs on the date of the estimate. Actual future prices and
+costs may differ materially from those used in the present value estimate.
+The discounted present value of our oil and gas reserves is prepared in accordance with guidelines
+established by the SEC. A purchaser of reserves would use numerous other factors to value the
+reserves. The discounted present value of reserves, therefore, does not necessarily represent the
+fair market value of those reserves.
+On December 31, 2007, approximately 80% of the discounted present value of our estimated net proved
+reserves was proved undeveloped. Proved undeveloped reserves represented 81% of total proved
+reserves. Most of these proved undeveloped reserves were attributable to our deepwater properties.
+Development of these properties is subject to additional risks as described above.
+Information about reserves constitutes forward-looking information. See “Forward-Looking
+Statements” for information regarding forward-looking information. 
+Unless we are able to replace reserves which we have produced, our cash flows and production will
+decrease over time. Our future success depends upon our ability to find, develop and acquire oil
+and gas reserves that are economically recoverable. As is generally the case for Gulf properties,
+our producing properties usually have high initial production rates, followed by a steep decline in
+production. As a result, we must continually locate and develop or acquire new oil and gas reserves
+to replace those being depleted by production. We must do this even during periods of low oil and
+gas prices when it is difficult to raise the capital necessary to finance these activities and
+during periods of high operating costs when it is expensive to contract for drilling rigs and other
+equipment and personnel necessary to explore for oil and gas. Without successful exploration or
+acquisition activities, our reserves, production and revenues will decline rapidly. We cannot
+assure you that we will be able to find and develop or acquire additional reserves at an acceptable
+cost.
+Also, because of the aggregate short life of our reserves, our return on the investment we make in
+our oil and gas wells and the value of our oil and gas wells will depend significantly on prices
+prevailing during relatively short production periods.
+A significant part of the value of our production and reserves is concentrated in a small number of
+offshore properties, and any production problems or inaccuracies in reserve estimates related to
+those properties would adversely impact our business. During 2007, approximately 63% of our daily
+production came from five of our properties in the Gulf of Mexico. Moreover, one property accounted
+for
+5 
+Table of Contents 
+24% of our production during this period. In addition, at December 31, 2007, most of our proved
+reserves were located in three fields in the Gulf of Mexico, with approximately 92% of our total
+net proved reserves attributable to these properties. If mechanical problems, storms or other
+events curtailed a substantial portion of this production or if the actual reserves associated with
+any one of these producing
+properties are less than our estimated reserves, our results of operations and financial condition
+could be adversely affected.
+Our focus on exploration projects increases the risks inherent in our oil and gas activities. Our
+business strategy focuses on replacing reserves through exploration, where the risks are greater
+than in acquisitions and development drilling. Although we have been successful in exploration in
+the past, we cannot assure you that we will continue to increase reserves through exploration or at
+an acceptable cost. Additionally, we are often uncertain as to the future costs and timing of
+drilling, completing and producing wells. Our drilling operations may be curtailed, delayed or
+canceled as a result of a variety of factors, including:
+• 
+unexpected drilling conditions; 
+• 
+pressure or inequalities in formations; 
+• 
+equipment failures or accidents; 
+• 
+adverse weather conditions; 
+• 
+governmental requirements; and 
+• 
+shortages or delays in the availability of drilling rigs and the delivery of equipment. 
+We do not operate all of our properties and have limited influence over the operations of some of
+these properties, particularly two of our deepwater properties. Our lack of control could result
+in the following:
+• 
+the operator may initiate exploration or development at a faster or slower pace than we
+prefer; 
+• 
+the operator may propose to drill more wells or build more facilities on a project than
+we have funds for or that we deem appropriate, which may mean that we are unable to
+participate in the project or share in the revenues generated by the project even though we
+paid our share of exploration costs; and 
+• 
+if an operator refuses to initiate a project, we may be unable to pursue the project. 
+Any of these events could materially reduce the value of our non-operated properties.
+Our deepwater operations have special operational risks that may negatively affect the value of
+those assets. Drilling operations in the deepwater area are by their nature more difficult and
+costly than drilling operations in shallow water. Deepwater drilling operations require the
+application of more advanced drilling technologies involving a higher risk of technological failure
+and usually have significantly higher drilling costs than shallow water drilling operations.
+Deepwater wells are completed using sub-sea completion techniques that require substantial time and
+the use of advanced remote installation equipment. These operations involve a high risk of
+mechanical difficulties and equipment failures that could result in significant cost overruns.
+In deepwater, the time required to commence production following a discovery is much longer than in
+shallow water and on-shore. Deepwater discoveries require the construction of expensive production
+facilities and pipelines prior to production. We cannot estimate the costs and timing of the
+construction of these facilities with certainty, and the accuracy of our estimates will be affected
+by a number of factors beyond our control, including the following:
+6 
+Table of Contents 
+• 
+decisions made by the operators of our deepwater wells; 
+• 
+the availability of materials necessary to construct the facilities; 
+• 
+the proximity of our discoveries to pipelines; 
+• 
+the price of oil and natural gas; and 
+• 
+regulatory requirements. 
+Delays and cost overruns in the commencement of production will affect the value of our deepwater
+prospects and the discounted present value of reserves attributable to those prospects.
+Competitive industry conditions may negatively affect our ability to conduct operations. We
+operate in the highly competitive areas of oil and gas exploration, development and production. We
+compete for the purchase of leases in the Gulf of Mexico granted by the U. S. government and from
+other oil and gas companies. These leases include exploration prospects as well as properties with
+proved reserves. Factors that affect our ability to compete in the marketplace include:
+• 
+our access to the capital necessary to drill wells and acquire properties; 
+• 
+our ability to acquire and analyze seismic, geological and other information relating to
+a property; 
+• 
+our ability to retain the personnel necessary to properly evaluate seismic and other
+information relating to a property; 
+• 
+the location of, and our ability to access, platforms, pipelines and other facilities
+used to produce and transport oil and gas production; 
+• 
+the standards we establish for the minimum projected return on an investment of our
+capital; and 
+• 
+the availability of alternate fuel sources. 
+Our competitors include major integrated oil companies, substantial independent energy companies,
+and affiliates of major interstate and intrastate pipelines and national and local gas gatherers,
+many of which possess greater financial, technological and other resources than we do.
+Our competitors may use superior technology, which we may be unable to afford or which would
+require costly investment by us in order to compete. Our industry is subject to rapid and
+significant advancements in technology, including the introduction of new products and services
+using new technologies. As our competitors use or develop new technologies, we may be placed at a
+competitive disadvantage, and competitive pressures may force us to implement new technologies at a
+substantial cost. In addition, our competitors may have greater financial, technical and personnel
+resources that allow them to enjoy technological advantages and may in the future allow them to
+implement new technologies before we can. We cannot be certain that we will be able to implement
+technologies on a timely basis or at a cost that is acceptable to us. One or more of the
+technologies that we currently use or that we may implement in the future may become obsolete, and
+we may be adversely affected. For example, marine seismic acquisition technology has been
+characterized by rapid technological advancements in recent years, and further significant
+technological developments could substantially impair our 3-D seismic data’s value.
+We may not be able to replace our reserves or generate cash flows if we are unable to raise
+capital. We will be required to make substantial capital expenditures to develop our existing
+reserves, and to discover new oil and gas reserves. Historically, we have financed these
+expenditures primarily with cash from operations, proceeds from bank borrowings and proceeds from
+the sale of debt and equity securities. See “Management’s Discussion and Analysis of Financial
+Condition and Results of Operations — Liquidity and Capital Resources” for a discussion of our
+capital budget. We cannot assure you that we
+7 
+Table of Contents 
+will be able to raise capital in the future. We also
+make offers to acquire oil and gas properties in the ordinary course of our business. If these
+offers are accepted, our capital needs may increase substantially.
+We expect to continue using our senior secured credit facility to borrow funds to supplement our
+available cash. The amount we may borrow under our senior secured credit facility may not exceed a
+borrowing base determined by the lenders under such facility based on their projections of our
+future production, production costs, taxes, commodity prices and any other factors deemed relevant
+by our lenders. We
+cannot control the assumptions the lenders use to calculate our borrowing base. The lenders may,
+without our consent, adjust the borrowing base semiannually or in situations where we purchase or
+sell assets or issue debt securities. If our borrowings under the senior secured credit facility
+exceed the borrowing base, the lenders may require that we repay the excess. If this were to occur,
+we might have to sell assets or seek financing from other sources. Sales of assets could further
+reduce the amount of our borrowing base. We cannot assure you that we would be successful in
+selling assets or arranging substitute financing. If we were not able to repay borrowings under
+our senior secured credit facility to reduce the outstanding amount to less than the borrowing
+base, we would be in default under our senior secured credit facility. For a description of our
+senior secured credit facility and its principal terms and conditions, see “Management’s Discussion
+and Analysis of Financial Condition and Results of Operations —Liquidity and Capital Resources”
+and Note 7 to our Consolidated Financial Statements.
+Our decision to drill a prospect is subject to a number of factors, and we may decide to alter our
+drilling schedule or not drill at all. A prospect is a property on which we have identified what
+our geoscientists believe, based on available seismic and geological information, to be indications
+of hydrocarbons. Our prospects are in various stages of evaluation, ranging from a prospect which
+is ready to drill to a prospect which will require substantial additional seismic data processing
+and interpretation. Whether we ultimately drill a prospect may depend on the following factors:
+• 
+receipt of additional seismic data or the reprocessing of existing data; 
+• 
+material changes in oil or gas prices; 
+• 
+the costs and availability of drilling rigs; 
+• 
+the success or failure of wells drilled in similar formations or which would use the
+same production facilities; 
+• 
+availability and cost of capital; 
+• 
+changes in the estimates of the costs to drill or complete wells; 
+• 
+our ability to attract other industry partners to acquire a portion of the working
+interest to reduce exposure to costs and drilling risks; and 
+• 
+decisions of our joint working interest owners. 
+We will continue to gather data about our prospects and it is possible that additional information
+may cause us to alter our drilling schedule or determine that a prospect should not be pursued at
+all. You should understand that our plans regarding our prospects are subject to change.
+Weather, unexpected subsurface conditions, and other unforeseen operating hazards may adversely
+impact our ability to conduct business. There are many operating hazards in exploring for and
+producing oil and gas, including:
+• 
+our drilling operations may encounter unexpected formations or pressures, which could
+cause damage to equipment or personal injury; 
+• 
+we may experience equipment failures which curtail or stop production; 
+8 
+Table of Contents 
+• 
+we could experience blowouts or other damages to the productive formations that may
+require a well to be re-drilled or other corrective action to be taken; and 
+• 
+because of these or other events, we could experience environmental hazards, including
+release of oil and gas from spills, gas leaks, and ruptures. 
+In the event of any of the foregoing, we may be subject to interrupted production or substantial
+environmental liability due to injury to persons or loss of life, damage to or destruction of
+property, natural resources and equipment, pollution and other environmental damage, investigation
+and remediation requirements, and fines and penalties and injunctive relief. Moreover, a
+substantial portion of
+our operations are offshore and are subject to a variety of risks peculiar to the marine
+environment such as capsizing, collisions, hurricanes and other adverse weather conditions, which
+can result in substantial damage to facilities and interrupt production, as well as more extensive
+governmental regulation.
+We cannot assure you that we will be able to maintain adequate insurance at rates we consider
+reasonable to cover our possible losses from operating hazards. The occurrence of a significant
+event not fully insured or indemnified against could materially and adversely affect our financial
+condition and results of operations.
+We may not have production to offset hedges; by hedging, we may not benefit from price increases. 
+Part of our business strategy is to reduce our exposure to the volatility of oil and gas prices by
+hedging a portion of our production. In a typical hedge transaction, we will have the right to
+receive from the other parties to the hedge the excess of the fixed price specified in the hedge
+over a floating price based on a market index, multiplied by the quantity hedged. If the floating
+price exceeds the fixed price, we are required to pay the other parties this difference multiplied
+by the quantity hedged. We are required to pay the difference between the floating price and the
+fixed price when the floating price exceeds the fixed price regardless of whether we have
+sufficient production to cover the quantities specified in the hedge. Significant reductions in
+production at times when the floating price exceeds the fixed price could require us to make
+payments under the hedge agreements even though such payments are not offset by sales of
+production. Hedging will also prevent us from receiving the full advantage of increases in oil or
+gas prices above the fixed amount specified in the hedge. We also enter into price “collars” to
+reduce the risk of changes in oil and gas prices. Under a collar, no payments are due by either
+party so long as the market price is above a floor set in the collar and below a ceiling. If the
+price falls below the floor, the counter-party to the collar pays the difference to us and if the
+price is above the ceiling, we pay the counter-party the difference. Another type of hedging
+contract we have entered into is a put contract. Under a put, if the price falls below the set
+floor price, the counter-party to the contract pays the difference to us. See “Quantitative and
+Qualitative Disclosures About Market Risks” for a discussion of our hedging practices.
+Compliance with environmental and other government regulations could be costly and could negatively
+impact production. Our operations are subject to numerous laws and regulations governing the
+operation and maintenance of our facilities and the discharge of materials into the environment or
+otherwise relating to environmental protection. For a discussion of the material regulations
+applicable to us, see “Regulations”. These laws and regulations may:
+• 
+require that we acquire permits before commencing drilling; 
+• 
+impose operational and other conditions on our activities; 
+• 
+restrict the substances that can be released into the environment in connection with
+drilling and production activities; 
+• 
+limit or prohibit drilling activities on protected areas such as wetlands, wilderness
+areas or coral reefs; and 
+9 
+Table of Contents 
+• 
+require measures to remediate or mitigate pollution and environmental impacts from
+current and former operations, such as cleaning up spills or dismantling abandoned
+production facilities. 
+Under these laws and regulations, we could be liable for costs of investigation, removal and
+remediation, damages to and loss of use of natural resources, loss of profits or impairment of
+earning capacity, property damages, costs of and increased public services, as well as
+administrative, civil and criminal fines and penalties, and injunctive relief. Under the common
+law, we could be liable for injuries to people and property. We maintain limited insurance
+coverage for sudden and accidental environmental damages. We do not believe that insurance coverage
+for environmental damages that occur over time is available at a reasonable cost. Also, we do not
+believe that insurance coverage for the full potential liability that could
+be caused by sudden and accidental environmental damages is available at a reasonable cost.
+Accordingly, we may be subject to liability or we may be required to cease production from
+properties in the event of environmental incidents.
+Factors beyond our control affect our ability to market production and our financial results. The
+ability to market oil and gas from our wells depends upon numerous factors beyond our control.
+These factors include:
+• 
+the extent of domestic production and imports of oil and gas; 
+• 
+the proximity of the gas production to gas pipelines; 
+• 
+the availability of pipeline capacity; 
+• 
+the demand for oil and gas by utilities and other end users; 
+• 
+the availability of alternative fuel sources; 
+• 
+the effects of inclement weather; 
+• 
+state and federal regulation of oil and gas marketing; and 
+• 
+federal regulation of gas sold or transported in interstate commerce. 
+Because of these factors, we may be unable to market all of the oil or gas we produce. In addition,
+we may be unable to obtain favorable prices for the oil and gas we produce.
+If oil and gas prices decrease, we may be required to take writedowns of the carrying value of our
+oil and gas properties. We may be required to writedown the carrying value of our oil and gas
+properties when oil and gas prices are low or if we have substantial downward adjustments to our
+estimated net proved reserves, increases in our estimates of development costs or deterioration in
+our exploration results. Under the full-cost method which we use to account for our oil and gas
+properties, the net capitalized costs of our oil and gas properties may not exceed the present
+value, discounted at 10%, of future net cash flows from estimated net proved reserves, using period
+end oil and gas prices or prices as of the date of our auditor’s report, plus the lower of cost or
+fair market value of our unproved properties. If net capitalized costs of our oil and gas
+properties exceed this limit, we must charge the amount of the excess to earnings. This type of
+charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity.
+We review the carrying value of our properties quarterly, based on prices in effect as of the end
+of each quarter or at the time of reporting our results. Once incurred, a writedown of oil and gas
+properties is not reversible at a later date, even if prices increase.
+There are inherent limitations in all control systems, and misstatements due to error or fraud that
+could seriously harm our business may occur and not be detected. Our management, including our
+Chief Executive and Financial Officers, do not expect that our internal controls and disclosure
+controls will prevent all possible error and all fraud. A control system, no matter how well
+conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of
+the control system are
+10 
+Table of Contents 
+met. In addition, the design of a control system must reflect the fact that
+there are resource constraints and the benefit of controls must be relative to their costs.
+Because of the inherent limitations in all control systems, an evaluation of controls can only
+provide reasonable assurance that all material control issues and instances of fraud, if any, in
+our company have been detected. These inherent limitations include the realities that judgments in
+decision-making can be faulty and that breakdowns can occur because of simple error or mistake.
+Further, controls can be circumvented by the individual acts of some persons or by collusion of two
+or more persons. The design of any system of controls is based in part upon certain assumptions
+about the likelihood of future events, and there can be no assurance that any design will succeed
+in achieving its stated goals under all potential future conditions. Because of inherent
+limitations in a cost-effective control system, misstatements due to error or fraud may occur and
+not be detected. A
+failure of our controls and procedures to detect error or fraud could seriously harm our business
+and results of operations.
+Forward-Looking Statements 
+In this report, we have made many forward-looking statements. We cannot assure you that the plans,
+intentions or expectations upon which our forward-looking statements are based will occur. Our
+forward-looking statements are subject to risks, uncertainties and assumptions, including those
+discussed elsewhere in this report. Forward-looking statements include statements regarding:
+• 
+our oil and gas reserve quantities, and the discounted present value of these
+reserves; 
+• 
+the amount and nature of our capital expenditures; 
+• 
+drilling of wells; 
+• 
+the timing and amount of future production and operating costs; 
+• 
+business strategies and plans of management; and 
+• 
+prospect development and property acquisitions. 
+Some of the risks, which could affect our future results and could cause results to differ
+materially from those expressed in our forward-looking statements, include:
+• 
+general economic conditions; 
+• 
+the volatility of oil and natural gas prices; 
+• 
+the uncertainty of estimates of oil and natural gas reserves; 
+• 
+the impact of competition; 
+• 
+the availability and cost of seismic, drilling and other equipment; 
+• 
+operating hazards inherent in the exploration for and production of oil and natural
+gas; 
+• 
+difficulties encountered during the exploration for and production of oil and
+natural gas; 
+• 
+difficulties encountered in delivering oil and natural gas to commercial markets; 
+• 
+changes in customer demand and producers’ supply; 
+• 
+the uncertainty of our ability to attract capital; 
+• 
+compliance with, or the effect of changes in, the extensive governmental
+regulations regarding the oil and natural gas business; 
+• 
+actions of operators of our oil and gas properties; and 
+• 
+weather conditions; and 
+• 
+climate change. 
+The information contained in this report, including the information set forth under the heading
+“Risk Factors,” identifies additional factors that could affect our operating results and
+performance. We urge you to carefully consider these factors and the other cautionary statements in
+this report. Our forward-looking
+11 
+Table of Contents 
+statements speak only as of the date made, and we have no
+obligation to update these forward-looking statements.
+Corporate Offices 
+Our headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned
+space. We also maintain a business office in Houston, Texas, and own or lease field offices in the
+area of the major fields in which we operate properties or have a significant interest. Replacement
+of any of our leased offices would not result in material expenditures by us as alternative
+locations to our leased space are anticipated to be readily available . 
+Employees 
+We had 85 employees as of December 31, 2007, none of whom are currently represented by a union. We
+believe that we have good relations with our employees. We employ seven petroleum engineers and
+eight petroleum geoscientists.
+Regulations 
+General . The oil and gas industry is subject to regulation at the federal, state and local level,
+and some of the laws, rules and regulations that govern our operations carry substantial penalties
+for non-compliance. This regulatory burden increases our cost of doing business and, consequently,
+affects our profitability.
+Exploration and Production. Our operations are subject to federal, state and local regulations
+that include requirements for permits to drill and to conduct other operations and for provision of
+financial assurances (such as bonds) covering drilling and well operations. Other activities
+subject to regulation are:
+• 
+the location of wells, 
+• 
+the method of drilling and completing wells, 
+• 
+the rate of production, 
+• 
+the surface use and restoration of properties upon which wells are drilled, 
+• 
+the plugging and abandoning of wells, 
+• 
+the discharge of contaminants into water and the emission of contaminants into air, 
+• 
+the disposal of fluids used or other wastes obtained in connection with operations, 
+• 
+the marketing, transportation and reporting of production, and 
+• 
+the valuation and payment of royalties. 
+For instance, our OCS leases in federal waters are administered by MMS, and require compliance with
+detailed MMS regulations and orders. Lessees must obtain MMS approval for exploration plans and
+exploitation and production plans prior to the commencement of such operations. The MMS has
+promulgated regulations requiring offshore production facilities located on the OCS to meet
+stringent engineering and construction specifications. The MMS also has regulations restricting
+the flaring or venting of natural gas, and prohibiting the flaring of liquid hydrocarbons and oil
+without prior authorization. MMS policies concerning the volume of production that a lessee must
+have to maintain an offshore lease beyond its primary term also are applicable to Callon.
+Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of
+wells located offshore and the installation and removal of all production facilities. To cover the
+various obligations of lessees on the OCS, the MMS generally requires that lessees have substantial
+net worth or post bonds or other acceptable assurances that
+12 
+Table of Contents 
+such obligations will be met. The cost
+of these bonds or other surety can be substantial, and there is no assurance that bonds or other
+surety can be obtained in all cases. Under some circumstances, the MMS may require any of our
+operations on federal leases to be suspended or terminated. Any such suspension or termination
+could materially adversely affect our financial conditions and results of operations.
+Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline
+transportation. The price and terms for access to pipeline transportation remain subject to
+extensive federal regulation. If these regulations change, we could face higher transmission costs
+for our production and, possibly, reduced access to transmission capacity.
+We do not currently anticipate that compliance with existing laws and regulations governing
+exploration and production will have a significantly adverse effect upon our capital expenditures,
+earnings or competitive position.
+Various proposals and proceedings that might affect the petroleum industry are pending before
+Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the
+courts. The industry historically has been heavily regulated and we can offer you no assurance
+that the less stringent regulatory approach recently pursued by the FERC and Congress will continue
+nor can we predict what effect such proposals or proceedings may have on our operations.
+Environmental Regulation. Various federal, state and local laws and regulations concerning the
+release of contaminants into the environment, including the discharge of contaminants into water
+and the emission of contaminants into the air, the generation, storage, treatment, transportation
+and disposal of wastes, and the protection of public health, welfare, and safety, and the
+environment, including natural resources, affect our exploration, development and production
+operations, including operations of our processing facilities. We must take into account the cost
+of complying with environmental regulations in planning, designing, drilling, constructing,
+operating and abandoning wells. Regulatory requirements relate to, among other things, the handling
+and disposal of drilling and production waste products, the control of water and air pollution and
+the removal, investigation, and remediation of petroleum-product contamination. In addition, our
+operations may require us to obtain permits for, among other things,
+• 
+air emissions, 
+• 
+discharges into surface waters, and 
+• 
+the construction and operations of underground injection wells or surface pits to
+dispose of produced saltwater and other nonhazardous oilfield wastes. 
+In the event of an unauthorized discharge, emission or other activity, we may be liable for, among
+other things, penalties, costs and damages, and subject to injunctive relief, and we could be
+required to cleanup or mitigate the environmental impacts of those discharges, emissions or
+activities. Under state and federal laws, the present and certain past owners and operators [of a
+site, and persons that treated, disposed of or arranged for the disposal of hazardous substances
+found at a site, may be liable, without regard to fault or the legality of the original conduct,
+for the release of hazardous substances into the environment. The Environmental Protection Agency,
+state environmental agencies and, in some cases third parties are authorized to take actions in
+response to threats to human health or the environment and to seek to recover from responsible
+classes of persons the costs of such] actions. We therefore could be required to remove or
+remediate previously disposed wastes and remediate contamination, including contamination in
+surface water, soil or groundwater, caused by disposal of that waste, irrespective of whether
+disposal or release were authorized. We could be responsible for wastes disposed of or released by
+us or prior owners or operators at properties owned or leased by us or at locations where wastes
+have been taken for disposal
+13 
+Table of Contents 
+also irrespective of whether disposal or release were authorized. We
+could also be required to suspend or cease operations in contaminated areas, or to perform remedial
+well plugging operations or cleanups to prevent future contamination.
+The Environmental Protection Agency and various state agencies have limited the disposal options
+for hazardous and nonhazardous wastes increasing costs of disposal. Furthermore, certain wastes
+generated by our oil and natural gas operations that are currently exempt from treatment as
+hazardous wastes may in the future be designated as hazardous wastes and, therefore, be subject to
+considerably more rigorous and costly operating and disposal requirements.
+Federal and state occupational safety and health laws require us to organize information about
+hazardous materials used, released or produced in our operations. Certain portions of this
+information must be provided to employees, state and local governmental authorities and local
+citizens. We are also subject to the requirements and reporting set forth in federal workplace
+standards.
+Recent scientific studies have suggested that man made emissions of certain gases, commonly
+referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to
+the warming of the atmosphere resulting in climate change. In response to such studies, the United
+States Congress is actively considering legislation to reduce emissions of greenhouse gases. In
+addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse
+gases, primarily through the planned development of greenhouse gas emission inventories and/or
+regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s
+decision on April 2, 2007 in Massachusetts v. EPA, the EPA may regulate greenhouse gas emissions
+from mobile sources (e.g., cars and trucks) and possibly from stationary sources as well under
+certain federal Clean Air Act programs, even if Congress does not adopt new legislation
+specifically addressing emissions of greenhouse gases. New legislation or regulatory programs that
+restrict emissions of greenhouse gases in areas where we conduct business could adversely affect
+our operations and the demand for hydrocarbon products generally. The impact of such future
+programs cannot be predicted, but we do not expect our operations to be affected any differently
+than other similarly situated domestic competitors.
+We have made and will continue to make expenditures to comply with environmental regulations and
+requirements. These are necessary business costs in the oil and gas industry. Although we are not
+fully insured against all environmental risks, we maintain insurance coverage which we believe is
+customary in the industry. Moreover, it is possible that other developments, such as stricter and
+more comprehensive environmental laws and regulations, as well as claims for damages to property or
+persons resulting from company operations, could result in substantial costs and liabilities, to
+Callon. We believe we are in compliance with existing environmental regulations, and that, absent
+the occurrence of an extraordinary event the effect of which cannot be predicted, any noncompliance
+will not have a material adverse effect on our operations or earnings.
+Commitments and Contingencies 
+The Company’s activities are subject to federal, state and local laws and regulations governing
+environmental quality and pollution control. Although no assurances can be made, the Company
+believes that, absent the occurrence of an extraordinary event, compliance with existing federal,
+state and local laws, rules and regulations governing the release of materials into the environment
+or otherwise relating to the protection of the environment will not have a material effect upon the
+capital expenditures, earnings or the competitive position of the Company with respect to its
+existing assets and operations. The Company cannot predict what effect additional regulation or
+legislation, enforcement polices thereunder, and claims for
+14 
+Table of Contents 
+damages to property, employees, other
+persons, and the environment resulting from the Company’s operations could have on its activities.
+Property Summary 
+We are engaged in the exploration, development, acquisition and production of oil and gas
+properties. Our properties are concentrated offshore in the Gulf of Mexico and onshore, primarily,
+in Louisiana. We have historically increased our reserves and production by focusing primarily on
+low to moderate risk exploration and acquisition opportunities in the Gulf of Mexico shelf area.
+In 1998, we expanded our area of exploration to include the Gulf of Mexico deepwater area. As of
+December 31, 2007, our estimated net proved reserves totaled 263.6 Bcfe and included 24.5 million
+barrels of oil (“MMBbls”) and 116.5 billion cubic feet of natural gas (“Bcf”), with a pre-tax
+present value, discounted at 10%, of the estimated future net revenues based on constant prices in
+effect at year-end of $1,591.5 million. Oil constitutes approximately 56% on an equivalent basis of
+our total estimated proved reserves and approximately 19% of our total estimated proved reserves
+are proved developed reserves.
+In April 2007 we acquired BP’s 80% interest in the Entrada Field which is located in the deepwater
+region of the Gulf of Mexico. We now own a 100% interest, operate and have begun development of
+the field. We currently expect first production from this deepwater discovery to be in early 2009.
+To help us fund development and achieve this production target, we have entered into an agreement
+to sell 50% of our working interest in the Entrada field to CIECO. See “Note 14 — Entrada
+Acquisition and Development” for more details.
+15 
+Table of Contents 
+Significant Properties 
+The following table shows discounted cash flows and net proved oil and gas reserves estimated by
+our independent petroleum reserve engineers by major field and for all other properties combined at
+December 31, 2007.
+Pre-tax 
+Discounted 
+Estimated Net Proved Reserves 
+Present 
+Oil 
+Gas 
+Total 
+Value 
+Operator 
+(MBbls) 
+(MMcf) 
+(MMcfe) 
+($000) 
+(a)(b)(c) 
+Gulf of Mexico Deepwater: 
+Garden Banks Block
+738/782/826/827
+“Entrada” 
+Callon 
+17,482 
+87,127 
+192,019 
+$ 
+1,144,110 
+Mississippi Canyon 538/582
+“Medusa” 
+Murphy 
+5,326 
+3,648 
+35,601 
+251,277 
+Garden Banks Block 341
+“Habanero” 
+Shell 
+1,457 
+5,681 
+14,425 
+113,015 
+Gulf of Mexico Shelf and Onshore: 
+High Island Blocks 165/130 
+StatoilHydro 
+23 
+4,320 
+4,459 
+18,851 
+East Cameron 2/LA 
+Callon 
+34 
+1,135 
+1,339 
+5,248 
+High Island Block A-540 
+Walter Oil & Gas Corp. 
+54 
+1,743 
+2,067 
+13,561 
+West Cameron Block 295 
+StatoilHydro/Cimarex 
+16 
+5,401 
+5,499 
+27,083 
+East Cameron Block 109 
+Energy Partners LTD 
+39 
+1,376 
+1,611 
+8,430 
+Other 
+Various 
+100 
+6,023 
+6,620 
+9,897 
+Total Net Proved Reserves 
+24,531 
+116,454 
+263,640 
+$ 
+1,591,472 
+(a) 
+Represents the present value of future net cash flows before deduction of federal income
+taxes, discounted at 10%, attributable to estimated net proved reserves as of December 31,
+2007, as set forth in the Company’s reserve reports prepared by its independent petroleum
+reserve engineers, Huddleston & Co., Inc. of Houston, Texas. Average pricing was $7.59 per
+Mcf for natural gas and $90.92 per Bbl for oil. 
+(b) 
+Includes a reduction for estimated plugging and abandonment costs that is reflected as a
+liability on our balance sheet at December 31, 2007, in accordance with Statement of Financial
+Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). See
+the Oil and Gas Reserve table for the standardized measure of discounted future net cash flow. 
+(c) 
+We use the financial measure “present value of estimated future net revenues from proved
+reserves, excluding income taxes.” This is a non-GAAP financial measure. We believe that
+present value of estimated future net revenues from proved reserves, excluding income taxes,
+while not a financial measure in accordance with generally accepted accounting principles, is
+an important financial measure used by investors and independent oil and gas producers for
+evaluating the relative value of oil and natural gas properties and acquisitions because the
+tax characteristics of comparable companies can differ materially. The total standardized
+measure for our proved reserves as of December 31, 2007 was $1.1 billion. The standardized
+measure gives effect to income taxes, and is calculated in accordance with Statement of
+Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities.”
+The standardized measure of our estimated net proved reserves of $1.1 billion equals the
+present value of our estimated future net revenue from proved reserves, excluding income
+taxes, of $1.6 billion, less discounted estimated future income taxes relating to such future
+net revenues of $457.5 million. 
+16 
+Table of Contents 
+Gulf of Mexico Deepwater 
+Entrada, Garden Banks Blocks 738/782/826/827 
+The Entrada discovery was drilled and delineated in 2000 with two wells and seven sidetracks on
+Garden Banks Block 782. Entrada is located in approximately 4,500 feet of water in the Gulf of
+Mexico. The Entrada Area is characterized by a northwest plunging salt ridge with multiple stacked
+amplitudes trapped against the salt and various faults. At year end 2006, we reclassified a portion
+of Entrada’s estimated net proved reserves to probable, as of December 31, 2006 due to new
+performance data from analogous deepwater reservoirs. Please refer to Note 15 of our Consolidated
+Financial Statements for further information regarding reserves.
+On April 18, 2007, we completed the acquisition of BP’s 80% working interest in the Entrada Field
+for a purchase price of $190 million. The purchase price included $150 million payable at closing
+and an additional $40 million payable after the achievement of certain production milestones. The
+purchased interests included five federal offshore blocks at Garden Banks Blocks 738, 782, 785, 826
+and 827, subject to certain depth limitations. The acquisition added 150 billion cubic feet of
+natural gas equivalent (Bcfe) to
+our proved undeveloped reserves. On December 31, 2007, we owned a 100% working interest in this
+discovery and are the operator.
+On February 11, 2008, we entered into an agreement to sell 50% of our working interest in the
+Entrada field. See “ Note 14 — Entrada Acquisition and Development” for more details.
+The Magnolia field is located on blocks adjacent to Entrada and the field and related production
+facilities are owned by Conoco/Phillips, the operator, and Devon Energy Corporation (“Devon”). In
+August 2007, we entered into a production handling agreement (“PHA”) with ConocoPhillips and Devon.
+The PHA provides for production from the Entrada Field, via a subsea tieback, to be processed
+through the Magnolia production platform.
+Work has been completed on a front-end engineering design study to tie-back Entrada to the Magnolia
+production facilities. Also, engineering work has been done and long lead items have been
+identified and orders are being placed. We have entered into a rig contact with Diamond Offshore
+Drilling, Inc. to use the Ocean Victory rig to drill and complete two development wells in the
+second half of 2008. The majority of development costs are anticipated to be incurred in 2008 and
+early 2009. First production is projected to commence in the first quarter of 2009.
+Medusa, Mississippi Canyon Blocks 538/582 
+Our Medusa deepwater discovery was announced in September 1999, after we drilled the initial test
+well in 2,235 feet of water to a total depth of 16,241 feet and encountered over 120 feet of pay in
+two intervals. Subsequent sidetrack drilling from the wellbore was used to determine the extent of
+the discovery, and a second well was drilled in the first quarter of 2000 to further delineate the
+extent of the pay intervals. We own a 15% working interest, Murphy Exploration & Production Company
+(“Murphy”), the operator, owns a 60% working interest and ENI Deepwater, LLC, owns the remaining
+25% working interest.
+In 2001, a drilling program began which included four development wells and one sidetrack. The
+program included production casing being set on six wells to provide initial production take-points
+and was completed in the first half of 2002. The construction of a floating production system,
+spar, at Medusa was completed during the second quarter of 2003. The A-1 well was completed and
+tied into the spar and commenced production in late November 2003. The remaining five wells were
+completed and
+17 
+Table of Contents 
+commenced production in 2004. Mississippi Canyon 538 #4, North Medusa, was drilled
+in 2003 and was temporarily abandoned after encountering 28 feet of net pay. The well bore was
+re-entered in the fourth quarter of 2004, sidetracked and reached an objective depth of 9,600 feet
+in January 2005. The sidetrack encountered 46 feet of net pay, was completed and commenced initial
+production in April 2005.
+During 2007 the field produced 4.5 Bcfe net to us which accounted for 24% of our total production.
+Future plans include five recompletions to produce up-hole sands and a new well and a sidetrack to
+undrained areas of the field up-dip or fault separated from existing production.
+In December 2003, we transferred our undivided 15% working interest in the spar production
+facilities to Medusa Spar LLC in exchange for cash proceeds of approximately $25 million and a 10%
+ownership interest in the LLC. A detailed discussion of this transaction is included in
+“Management’s Discussion and Analysis of Financial Condition and Results of Operations-Off-Balance
+Sheet Arrangements”.
+Habanero, Garden Banks Block 341 
+During February 1999, the initial test well on our Habanero deepwater discovery encountered over
+200 feet of net pay in two zones. Located in 2,015 feet of water, the well was drilled to a
+measured depth of 21,158 feet. We own an 11.25% working interest in the well. The well is operated
+by Shell Deepwater Development Inc., which owns a 55% working interest, with the remaining working
+interest being owned by Murphy.
+A field delineation program began in mid-year 2001, which included three sidetracks of the
+discovery well. Production casing was set on this well through the last of the sidetracks to the
+Habanero 52 oil and gas sand and the Habanero 55 gas sand. Also, a development well was drilled in
+the summer of 2003 which provides a take-point for production from the Habanero 52 oil sand. By
+means of a sub-sea completion and tie-back to an existing production facility in the area operated
+by Shell, production from the Habanero 52 oil sand commenced in late November 2003 and from the
+Habanero 55 gas sand in January 2004. In July 2004, the #2 well producing the Habanero 52 oil sand
+developed mechanical difficulties with a subsurface control valve and was shut-in resulting in a
+significant loss of production. Repairs were completed and production was restored in late
+December 2004. In addition, the #1 well producing the Habanero 55 gas sand was recompleted to the
+Habanero 55 oil sand in December 2004.
+At the time the field was developed, there was no way to know what the drive mechanism would be in
+the Habanero 52 oil sand, so the wells were drilled in a mid-dip position. It is now known that
+the Habanero 52 oil sand has strong water support requiring a well at structural crest for maximum
+recovery. A sidetrack of the #1 well was completed in the third quarter of 2007 at a structurally
+high position.
+Future plans include a sidetrack of the #2 well across a fault to drain a separate gas reservoir.
+During 2007, Habanero produced 1.6 Bcfe net to us which accounted for 9% of our total production.
+Gulf of Mexico Shelf and Onshore Louisiana 
+High Island Blocks 165/130 
+The High Island 165 #1 well was spud in the fourth quarter of 2005, reached total depth of 17,029
+feet in January 2006 and logged 140 feet of net pay in the Gyro K-1 and Rob L sands. We have
+drilled two
+18 
+Table of Contents 
+development wells, the High Island Block 130 #1 and #2 wells. Both development wells
+found pay in the Gyro K-1 sand and a deeper Gyro K-2 sand. The High Island 165 #1 well and the
+High Island 130 #1 well each produce from the Gyro K-1 sand which is nearing depletion. The High
+Island 130 #2 is producing the Gyro K-2 sand. The High Island 130 #1 well will be recompleted to
+the Rob L sand upon depletion. The High Island 165/130 field produced 2.5 Bcfe net to our interest
+in 2007. We have a 16.7% working interest in the Gyro K-1 and Rob L sands and an 11.7% interest in
+the Gyro K-1 sand. The operator of the field is StatoilHydro.
+High Island Block A-540 
+The #1 well was spud in November 2005 and reached a total depth of 9,450 feet the following month
+after logging 32 feet of net pay in the objective section. First production commenced in late
+September 2006 and during 2007 the field produced 1.5 Bcfe net to us. The company owns a 60%
+working interest and Walter Oil and Gas is the operator.
+West Cameron Block 295 
+During the third quarter of 2005, the #2 well reached a total depth of 15,775 feet and logged 150
+feet of net pay in two zones. Each zone was encountered at the predicted depth and exceeded
+anticipated thickness. The #2 well commenced production in the second quarter of 2006 and
+encountered mechanical difficulties which were corrected. Sustained production was achieved by the
+third quarter of 2006. In 2006, we drilled the #4 well, an offset to the #2 well. The #4 well
+commenced production during December 2006 in a deeper, secondary zone. After this zone is depleted
+we expect to recomplete the well in the main pay zone. Callon holds a 20.5% working interest in the
+block and StatoilHydro is the operator.
+A second prospect on this block was also drilled during 2005. The #3 well was drilled to a depth
+of 16,286 feet in December 2005 and logged 110 feet of net (94 feet true vertical depth) pay in two
+zones. The well was completed in a deeper secondary zone and will probably be recompleted to the
+main pay zone in early 2008. The well commenced production in August 2006. Callon holds a 20.5%
+working interest in the block and Cimarex Energy Company is the operator.
+During 2007, the West Cameron 295 field produced 1.5 Bcfe net to us.
+East Cameron 109 
+During 2006, an exploratory well was drilled to a vertical depth of 13,110 feet and encountered 54
+feet of net pay. The well produced 0.4 Bcfe net to us in 2007. Callon owns a 25% working interest
+and Energy Partners, LTD is the operator.
+East Cameron 2/LA 
+The State Lease 18121 #1 well was drilled to a vertical depth of 14,851 feet and encountered 20
+feet of net pay in August, 2007. The well was completed in October. First production is expected
+in the second quarter of 2008. Callon owns a 42.5% working interest and is the operator.
+19 
+Table of Contents 
+Oil and Gas Reserves 
+The following table sets forth certain information about our estimated proved reserves as reported
+by Huddleston & Co., Inc. as of the dates set forth below.
+Years Ended December 31, 
+2007 
+2006 
+2005 
+(In thousands) 
+Proved developed: 
+Oil (Bbls) 
+4,723 
+5,159 
+7,323 
+Gas (Mcf) 
+22,340 
+36,750 
+30,982 
+Mcfe 
+50,678 
+67,704 
+74,921 
+Proved undeveloped: 
+Oil (Bbls) 
+19,808 
+8,106 
+11,105 
+Gas (Mcf) 
+94,114 
+29,287 
+47,039 
+Mcfe 
+212,964 
+77,924 
+113,667 
+Total proved: 
+Oil (Bbls) 
+24,531 
+13,265 
+18,428 
+Gas (Mcf) 
+116,454 
+66,037 
+78,021 
+Mcfe 
+263,640 
+145,628 
+188,588 
+Estimated pre-tax future net cash flows (a) 
+$ 
+2,317,905 
+$ 
+775,742 
+$ 
+1,487,817 
+Pre-tax discounted present value (a) (b) 
+$ 
+1,591,472 
+$ 
+534,743 
+$ 
+1,088,714 
+Standardized measure of discounted future
+net cash flows(a) (b) 
+$ 
+1,133,989 
+$ 
+470,791 
+$ 
+837,552 
+(a) 
+Includes a reduction for estimated plugging and abandonment costs that is reflected as
+a liability on our balance sheet at December 31, 2007, in accordance with SFAS 143. 
+(b) 
+We use the financial measure “present value of estimated future net revenues from
+proved reserves, excluding income taxes.” This is a non-GAAP financial measure. We
+believe that present value of estimated future net revenues from proved reserves, excluding
+income taxes, while not a financial measure in accordance with generally accepted
+accounting principles, is an important financial measure used by investors and independent
+oil and gas producers for evaluating the relative value of oil and natural gas properties
+and acquisitions because the tax characteristics of comparable companies can differ
+materially. The total standardized measure for our proved reserves as of December 31, 2007
+was $1.1 billion. The standardized measure gives effect to income taxes, and is calculated
+in accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About
+Oil and Gas Producing Activities.” The standardized measure of our estimated net proved
+reserves of $1.1 billion equals the present value of our estimated future net revenue from
+proved reserves, excluding income taxes, of $1.6 billion, less discounted estimated future
+income taxes relating to such future net revenues of $457.5 million. Average pricing was
+$7.59 per Mcf for natural gas and $90.92 per Bbl for oil. 
+20 
+Table of Contents 
+Our independent reserve engineers, Huddleston & Co., Inc., prepared the estimates of the proved
+reserves and the future net cash flows and present value thereof attributable to such proved
+reserves. Reserves were estimated using oil and gas prices and production and development costs in
+effect on December 31 of each such year, without escalation, and were otherwise prepared in
+accordance with SEC regulations regarding disclosure of oil and gas reserve information.
+There are numerous uncertainties inherent in estimating quantities of proved reserves, including
+many factors beyond our control or the control of the reserve engineers. Reserve engineering is a
+subjective process of estimating underground accumulations of oil and gas that cannot be measured
+in an exact manner. The accuracy of any reserve or cash flow estimate is a function of the quality
+of available data and of engineering and geological interpretation and judgment. Estimates by
+different engineers often vary, sometimes significantly. In addition, physical factors, such as
+the results of drilling, testing and production subsequent to the date of an estimate, as well as
+economic factors, such as an increase or decrease in product prices that renders production of such
+reserves more or less economic, may justify revision of such estimates. Accordingly, reserve
+estimates could be different from the quantities of oil and gas that are ultimately recovered.
+We have not filed any reports with other federal agencies which contain an estimate of total proved
+net oil and gas reserves during our last fiscal year.
+Present Activities and Productive Wells 
+The following table sets forth the wells we have drilled and completed during the periods
+indicated. All such wells were drilled in the continental United States primarily in federal and
+state waters in the Gulf of Mexico.
+Years Ended December 31, 
+2007 
+2006 
+2005 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development: 
+Oil 
+1 
+0.25 
+— 
+— 
+1 
+0.15 
+Gas 
+1 
+0.12 
+2 
+0.37 
+— 
+— 
+Non-productive 
+— 
+— 
+— 
+— 
+— 
+— 
+Total 
+2 
+0.37 
+2 
+0.37 
+1 
+0.15 
+Exploration: 
+Oil 
+— 
+— 
+— 
+— 
+— 
+— 
+Gas 
+2 
+0.63 
+5 
+2.05 
+7 
+2.42 
+Non-productive 
+3 
+0.47 
+8 
+2.98 
+4 
+1.25 
+Total 
+5 
+1.10 
+13 
+5.03 
+11 
+3.67 
+21 
+Table of Contents 
+The following table sets forth our productive wells as of December 31, 2007:
+Wells 
+Gross 
+Net 
+Oil: 
+Working interest 
+9.00 
+1.41 
+Royalty interest 
+— 
+— 
+Total 
+9.00 
+1.41 
+Gas: 
+Working interest 
+24.00 
+9.25 
+Royalty interest 
+6.00 
+0.18 
+Total 
+30.00 
+9.43 
+A well is categorized as an oil well or a natural gas well based upon the ratio of oil to gas
+reserves on a Mcfe basis. However, some of our wells produce both oil and gas. At December 31,
+2007, we had no wells with multiple completions. At December 31, 2007, two gross (0.22 net)
+exploration gas wells were in progress.
+Leasehold Acreage 
+The following table shows our approximate developed and undeveloped (gross and net) leasehold
+acreage as of December 31, 2007.
+Leasehold Acreage 
+Developed 
+Undeveloped 
+Location 
+Gross 
+Net 
+Gross 
+Net 
+Louisiana 
+4,472 
+2,050 
+7,091 
+2,940 
+Texas 
+2,160 
+1,080 
+11,920 
+8,600 
+Federal waters 
+88,370 
+39,101 
+343,865 
+157,967 
+Total 
+95,002 
+42,231 
+362,876 
+169,507 
+22 
+Table of Contents 
+Major Customers 
+Our production is sold generally on month-to-month contracts at prevailing prices. The following
+table identifies customers to whom we sold a significant percentage of our total oil and gas
+production during each of the 12-month periods ended:
+December 31, 
+2007 
+2006 
+2005 
+Shell Trading Company 
+25 
+% 
+41 
+% 
+34 
+% 
+Louis Dreyfus Energy Services 
+20 
+% 
+25 
+% 
+16 
+% 
+StatoilHydro 
+13 
+% 
+— 
+— 
+Plains Marketing, L.P. 
+10 
+% 
+11 
+% 
+16 
+% 
+Walter Oil and Gas Corporation 
+8 
+% 
+— 
+— 
+Chevron Texaco Natural Gas 
+— 
+3 
+% 
+10 
+% 
+Because alternative purchasers of oil and gas are readily available, we believe that the loss of
+any of these purchasers would not result in a material adverse effect on our ability to market
+future oil and gas production.
+Title to Properties 
+We believe that the title to our oil and gas properties is good and defensible in accordance with
+standards generally accepted in the oil and gas industry, subject to such exceptions which, in our
+opinion, are not so material as to detract substantially from the use or value of such properties.
+Our properties are typically subject, in one degree or another, to one or more of the following:
+• 
+royalties and other burdens and obligations, express or implied, under oil and gas
+leases; 
+• 
+overriding royalties and other burdens created by us or our predecessors in title; 
+• 
+a variety of contractual obligations (including, in some cases, development obligations)
+arising under operating agreements, farmout agreements, production sales contracts and
+other agreements that may affect the properties or their titles; 
+• 
+back-ins and reversionary interests existing under purchase agreements and leasehold
+assignments; 
+• 
+liens that arise in the normal course of operations, such as those for unpaid taxes,
+statutory liens securing obligations to unpaid suppliers and contractors and contractual
+liens under operating agreements; 
+• 
+pooling, unitization and communitization agreements, declarations and orders; and 
+• 
+easements, restrictions, rights-of-way and other matters that commonly affect property. 
+To the extent that such burdens and obligations affect our rights to production revenues, they have
+been taken into account in calculating our net revenue interests and in estimating the size and
+value of our reserves. We believe that the burdens and obligations affecting our properties are
+conventional in the industry for properties of the kind owned by us.
+23 
+Table of Contents 
+ITEM 3. LEGAL PROCEEDINGS 
+We are a defendant in various legal proceedings and claims, which arise in the ordinary course of
+our business. We do not believe the ultimate resolution of any such actions will have a material
+affect on our financial position or results of operations.
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 
+There were no matters submitted to a vote of security holders during the fourth quarter of 2007.
+24 
+Table of Contents 
+PART II. 
+ITEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED
+STOCKHOLDER MATTERS 
+Our common stock trades on the New York Stock Exchange under the symbol “CPE”. The following table
+sets forth the high and low sale prices per share as reported for the periods indicated.
+Quarter Ended 
+High 
+Low 
+2006: 
+First quarter 
+$ 
+21.25 
+$ 
+17.01 
+Second quarter 
+21.99 
+15.12 
+Third quarter 
+19.96 
+12.54 
+Fourth quarter 
+17.44 
+12.48 
+2007: 
+First quarter 
+$ 
+15.00 
+$ 
+12.54 
+Second quarter 
+15.19 
+13.26 
+Third quarter 
+15.68 
+11.50 
+Fourth quarter 
+17.21 
+13.33 
+As of March 10, 2007 there were approximately 3,699 common stockholders of record.
+We have never paid dividends on our common stock and intend to retain our cash flow from operations
+for the future operation and development of our business. In addition, our primary credit facility
+and the terms of our outstanding subordinated debt prohibit the payment of cash dividends on our
+common stock.
+25 
+Table of Contents 
+Performance Graph 
+The following graph compares the yearly percentage change for the five years ended December 31,
+2007, in the cumulative total shareholder return on the Company’s Common Stock against the
+cumulative total return for the (i) Hemscott Industry and Market Index of SIC Group 123 (the
+“Hemscott Group Index”) consisting of independent oil and gas drilling and exploration companies
+and (ii) the New York Stock Exchange Market Index. The comparison of total return on an investment
+for each of the periods assumes that $100 was invested on December 31, 2002 in the Company, the
+Hemscott Group Index and the New York Stock Exchange Market Index, and that all dividends were
+reinvested.
+2002 
+2003 
+2004 
+2005 
+2006 
+2007 
+Callon Petroleum Company 
+$ 
+100 
+$ 
+310 
+$ 
+432 
+$ 
+527 
+$ 
+449 
+$ 
+491 
+Hemscott Group Index 
+$ 
+100 
+$ 
+131 
+$ 
+184 
+$ 
+290 
+$ 
+343 
+$ 
+539 
+NYSE Market Index 
+$ 
+100 
+$ 
+130 
+$ 
+146 
+$ 
+158 
+$ 
+186 
+$ 
+195 
+ITEM 6. SELECTED FINANCIAL DATA 
+The following table sets forth, as of the dates and for the periods indicated, selected financial
+information about us. The financial information for each of the five years in the period ended
+December 31, 2007 has been derived from our audited Consolidated Financial Statements for such
+periods. The information should be read in conjunction with “Management’s Discussion and Analysis
+of Financial Condition and Results of Operations” and the Consolidated Financial Statements and
+Notes thereto. The following information is not necessarily indicative of our future results.
+26 
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+SELECTED HISTORICAL FINANCIAL INFORMATION 
+(In thousands, except per share amounts) 
+Years Ended December 31, 
+2007 
+2006 
+2005 
+2004 
+2003 
+Statement of Operations Data: 
+Operating revenues: 
+Oil and gas sales 
+$ 
+170,768 
+$ 
+182,268 
+$ 
+141,290 
+$ 
+119,802 
+$ 
+73,697 
+Operating expenses: 
+Lease operating expenses 
+27,795 
+28,881 
+24,377 
+22,308 
+11,301 
+Depreciation, depletion and amortization 
+72,762 
+65,283 
+44,946 
+47,453 
+28,253 
+General and administrative 
+9,876 
+8,591 
+8,085 
+8,758 
+4,713 
+Accretion expense 
+3,985 
+4,960 
+3,549 
+3,400 
+2,884 
+Derivative expense 
+— 
+150 
+6,028 
+1,371 
+535 
+Total operating expenses 
+114,418 
+107,865 
+86,985 
+83,290 
+47,686 
+Income from operations 
+56,350 
+74,403 
+54,305 
+36,512 
+26,011 
+Other (income) expenses: 
+Interest expense 
+34,329 
+16,480 
+16,660 
+20,137 
+30,614 
+Other (income) 
+(1,172 
+) 
+(1,869 
+) 
+(998 
+) 
+(357 
+) 
+(444 
+) 
+Loss on early extinguishment of debt 
+— 
+— 
+— 
+3,004 
+5,573 
+Total other (income) expenses 
+33,157 
+14,611 
+15,662 
+22,784 
+35,743 
+Income (loss) before income taxes 
+23,193 
+59,792 
+38,643 
+13,728 
+(9,732 
+) 
+Income tax expense (benefit) 
+8,506 
+20,707 
+13,209 
+(6,697 
+) 
+8,432 
+Income (loss) before equity in earnings of Medusa Spar LLC
+and cumulative effect of change in accounting principle 
+14,687 
+39,085 
+25,434 
+20,425 
+(18,164 
+) 
+Equity in earnings of Medusa Spar LLC, net of tax 
+507 
+1,475 
+1,342 
+1,076 
+(8 
+) 
+Income (loss) before cumulative effect of change in
+in accounting principle 
+15,194 
+40,560 
+26,776 
+21,501 
+(18,172 
+) 
+Cumulative effect of change in accounting principle,
+net of tax 
+— 
+— 
+— 
+— 
+181 
+Net income (loss) 
+15,194 
+40,560 
+26,776 
+21,501 
+(17,991 
+) 
+Preferred stock dividends 
+— 
+— 
+318 
+1,272 
+1,277 
+Net income (loss) available to common shares 
+$ 
+15,194 
+$ 
+40,560 
+$ 
+26,458 
+$ 
+20,229 
+$ 
+(19,268 
+) 
+27 
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+SELECTED HISTORICAL FINANCIAL INFORMATION 
+(In thousands, except per share amounts) 
+Years Ended December 31, 
+2007 
+2006 
+2005 
+2004 
+2003 
+Net income (loss) per common share: 
+Basic: 
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+0.73 
+$ 
+2.00 
+$ 
+1.43 
+$ 
+1.28 
+$ 
+(1.42 
+) 
+Cumulative effect of change in accounting principle,
+net of tax 
+— 
+— 
+— 
+— 
+.01 
+Net income (loss) available to common 
+$ 
+0.73 
+$ 
+2.00 
+$ 
+1.43 
+$ 
+1.28 
+$ 
+(1.41 
+) 
+Diluted: 
+Net income (loss) available to common before cumulative
+effect of change in accounting principle 
+$ 
+0.71 
+$ 
+1.90 
+$ 
+1.28 
+$ 
+1.22 
+$ 
+(1.42 
+) 
+Cumulative effect of change in accounting principle,
+net of tax 
+— 
+— 
+— 
+— 
+.01 
+Net income (loss) available to common 
+$ 
+0.71 
+$ 
+1.90 
+$ 
+1.28 
+$ 
+1.22 
+$ 
+(1.41 
+) 
+Shares used in computing net income (loss) per common share: 
+Basic 
+20,776 
+20,270 
+18,453 
+15,796 
+13,662 
+Diluted 
+21,290 
+21,363 
+20,883 
+17,678 
+13,662 
+Balance Sheet Data (end of period): 
+Oil and gas properties, net 
+$ 
+681,706 
+$ 
+547,027 
+$ 
+447,364 
+$ 
+406,690 
+$ 
+390,163 
+Total assets 
+$ 
+792,482 
+$ 
+625,527 
+$ 
+533,776 
+$ 
+457,523 
+$ 
+496,032 
+Long-term debt, less current portion 
+$ 
+392,012 
+$ 
+225,521 
+$ 
+188,813 
+$ 
+192,351 
+$ 
+214,885 
+Stockholders’ equity 
+$ 
+287,075 
+$ 
+281,363 
+$ 
+228,048 
+$ 
+198,312 
+$ 
+133,261 
+We follow the full-cost method of accounting for oil and gas properties. Under this method of
+accounting, our net capitalized costs to acquire, explore and develop oil and gas properties may
+not exceed the sum of (1) the estimated future net revenues from proved reserves at current prices
+discounted at 10% and (2) the lower of cost or market of unevaluated properties, net of tax (the
+full-cost ceiling amount). If these capitalized costs exceed the full-cost ceiling amount, the
+excess is charged to expense.
+28 
+Table of Contents 
+ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
+RESULTS OF OPERATIONS 
+The following discussion is intended to assist in an understanding of our financial condition and
+results of operations. Our consolidated financial statements and notes thereto contain detailed
+information that should be referred to in conjunction with the following discussion. See Item 8
+“Financial Statements and Supplementary Data.”
+General 
+We have been engaged in the exploration, development, acquisition and production of oil and gas
+properties since 1950. Our revenues, profitability and future growth and the carrying value of our
+oil and gas properties are substantially dependent on prevailing prices of oil and gas and our
+ability to find, develop and acquire additional oil and gas reserves that are economically
+recoverable. Our ability to maintain or increase our borrowing capacity and to obtain additional
+capital on attractive terms is also influenced by oil and gas prices.
+Significant events for the year ended December 31, 2007 included:
+• 
+the completion of the acquisition of BP’s working interest in the Entrada Field for a
+purchase price of $190 million with a cash payment of $150 million at closing; 
+• 
+the seven-year $200 million senior revolving credit facility arranged by Merrill Lynch
+Capital Corporation to finance the BP acquisition; 
+• 
+the production handling agreement entered into with ConocoPhillips and Devon Energy
+Corporation to use their Magnolia production facility located on an adjacent block to host
+production from Entrada; 
+• 
+the drilling contract entered into with Diamond Offshore Drilling, Inc. for the Ocean
+Victory drilling rig to be used to drill and complete two development wells at Entrada; 
+• 
+retaining Merrill Lynch Petrie Divestiture Advisors to assist with the search to
+identify a partner to participate in the Entrada field development and entering into an
+agreement with CIECO subsequent to December 31, 2007 to sell 50% of our working interest
+in the Entrada field; and 
+• 
+the sale of our non-core, non-operated royalty and mineral interest properties, the
+proceeds of which will be used to help develop the Entrada Field. 
+Our estimated net proved oil and gas reserves increased at December 31, 2007 to 263.6 Bcfe. This
+represents an increase of 81% from previous year-end 2006 estimated proved reserves of 145.6 Bcfe.
+Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in
+the supply of and demand for oil and gas, market uncertainty and a variety of additional factors
+beyond our control. These factors include weather conditions in the United States, the condition
+of the United States economy, the actions of the Organization of Petroleum Exporting Countries,
+governmental regulation, political stability in the Middle East and elsewhere, the foreign supply
+of crude oil and natural gas, the price of foreign imports and the availability of alternate fuel
+sources. Any substantial and extended decline in the price of crude oil or natural gas would have
+an adverse effect on our carrying value of the proved reserves, borrowing capacity, revenues,
+profitability and cash flows from operations. We use derivative financial instruments (see Note 8
+to our consolidated financial statements and Item 7A. “Quantitative and Qualitative Disclosures
+About Market Risks”) for price protection purposes on a limited amount of our future production and
+do not use these instruments for trading purposes. On a Mcfe basis, natural gas represents
+approximately 55% of budgeted 2008 production and 44% of proved reserves at year-end 2007.
+29 
+Table of Contents 
+Inflation has not had a material impact on us and is not expected to have a material impact on us
+in the future.
+Summary of Significant Accounting Policies 
+Property and Equipment. We follow the full-cost method of accounting for oil and gas properties
+whereby all costs incurred in connection with the acquisition, exploration and development of oil
+and gas reserves, including certain overhead costs, are capitalized into the “full-cost pool.” The
+amounts we capitalize into the full-cost pool are depleted (charged against earnings) using the
+unit-of-production method. The full-cost method of accounting for our proved oil and gas
+properties requires that we make estimates based on assumptions as to future events that could
+change. These estimates are described below.
+Depreciation, Depletion and Amortization (DD&A) of Oil and Gas Properties . We calculate depletion
+by using the net capitalized costs in our full-cost pool plus estimated future development costs
+(combined, the depletable base) and our estimated net proved reserve quantities. Capitalized
+costs added to the full-cost pool include the following:
+• 
+the cost of drilling and equipping productive wells, dry hole costs, acquisition costs
+of properties with proved reserves, delay rentals and other costs related to exploration
+and development of our oil and gas properties; 
+• 
+our payroll and general and administrative costs and costs related to fringe benefits
+paid to employees directly engaged in the acquisition, exploration and/or development of
+oil and gas properties as well as other directly identifiable general and administrative
+costs associated with such activities. Such capitalized costs do not include any costs
+related to our production of oil and gas or our general corporate overhead; 
+• 
+costs associated with properties that do not have proved reserves classified as
+unevaluated property costs and are excluded from the depletable base. These unevaluated
+property costs are added to the depletable base at such time as wells are completed on the
+properties, the properties are sold or we determine these costs have been impaired. Our
+determination that a property has or has not been impaired (which is discussed below)
+requires that we make assumptions about future events; 
+• 
+estimated costs to dismantle, abandon and restore properties that are capitalized to the
+full-cost pool when the related liabilities are incurred under SFAS 143; and 
+• 
+our estimates of future costs to develop proved properties are added to the full-cost
+pool for purposes of the DD&A computation. We use assumptions based on the latest
+geologic, engineering, regulatory and cost data available to us to estimate these amounts.
+However, the estimates we make are subjective and may change over time. Our estimates of
+future development costs are periodically updated as additional information becomes
+available. 
+Capitalized costs included in the full-cost pool plus estimated future development costs are
+depleted and charged against earnings using the unit-of-production method. Under this method, we
+estimate the proved reserves quantities at the beginning of each accounting period. For each Mcfe
+produced during the period, we record a depletion charge equal to the amount included in the
+depletable base (net of accumulated depreciation, depletion and amortization) divided by our
+estimated net proved reserve quantities.
+Because we use estimates and assumptions to calculate proved reserves (as discussed below) and the
+amounts included in the depletable base, our depletion rates may materially change if actual
+results differ from these estimates.
+30 
+Table of Contents 
+Ceiling Test . Under the full-cost accounting rules of the SEC, we review the carrying value of our
+proved oil and gas properties each quarter. Under these rules, capitalized costs of oil and gas
+properties, net of accumulated depreciation, depletion and amortization and deferred income taxes,
+may not exceed the present value of estimated future net cash flows from proved oil and gas
+reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of
+related tax effects (the full-cost ceiling amount). These rules generally require pricing future
+oil and gas production at the unescalated market price for oil and gas at the end of each fiscal
+quarter and require a write-down if the “ceiling” is exceeded. However, if prices recover
+sufficiently subsequent to the balance sheet date before the release of the financial statements
+then use of the subsequent pricing is allowed and no write-down would be required. Given the
+volatility of oil and gas prices, it is reasonably possible that our estimate of discounted future
+net cash flows from proved oil and gas reserves could change in the near term. If oil and gas
+prices decline significantly, even if only for a short period of time, it is possible that
+write-downs of oil and gas properties could occur in the future.
+Estimating Reserves and Present Value of Estimated Future Net Cash Flows . The estimates of
+quantities of proved oil and gas reserves and the discounted present value of estimated future net
+cash flows from such reserves at the end of each quarter are based on numerous assumptions, which
+are likely to change over time. These assumptions include:
+• 
+the prices at which we can sell our oil and gas production in the future. Oil and gas
+prices are volatile, but we are required to assume that they will not change from the
+prices in effect at the end of the quarter. In general, higher oil and gas prices will
+increase quantities of proved reserves and the present value of estimated future net cash
+flows from such reserves, while lower prices will decrease these amounts. Because our
+properties have relatively short productive lives, changes in prices will affect the
+present value of estimated future net cash flows more than the estimated quantities of oil
+and gas reserves; 
+• 
+the costs to develop and produce our reserves and the costs to dismantle our production
+facilities when reserves are depleted. These costs are likely to change over time, but we
+are required to assume that costs in effect at the end of the quarter will not change.
+Increases in costs will reduce estimated oil and gas quantities and the present value of
+estimated future net cash flows, while decreases in costs will increase such amounts.
+Because our properties have relatively short productive lives, changes in costs will affect
+the present value of estimated future net cash flows more than the estimated quantities of
+oil and gas reserves; and 
+• 
+the potential royalties payable to the Mineral Management Service. See Note 9 of our
+consolidated financial statements for a more detailed discussion. 
+In addition, the process of estimating proved oil and gas reserves requires that our independent
+and internal reserve engineers exercise judgment based on available geological, geophysical and
+technical information. We have described the risks associated with reserve estimation and the
+volatility of oil and gas prices under “Risk Factors”.
+Unproved Properties . Costs associated with properties that do not have proved reserves, including
+capitalized interest, are excluded from the depletable base. These unproved properties are
+included in the line item “Unevaluated properties excluded from amortization.” Unproved property
+costs are transferred to the depletable base when wells are completed on the properties or the
+properties are sold. In addition, we are required to determine whether our unproved properties are
+impaired and, if so, include the costs of such properties in the depletable base. We determine
+whether an unproved property should be impaired by periodically reviewing our exploration program
+on a property by property basis. This determination may require the exercise of substantial
+judgment by our management.
+31 
+Table of Contents 
+Asset Retirement Obligations. We account for asset retirement obligations in accordance with
+Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”
+(“SFAS 143”), which essentially requires entities to record the fair value of a liability for
+obligations associated with the retirement of tangible long-lived assets and the associated asset
+retirement costs. Interest is accreted on the present value of the asset retirement obligation and
+reported as accretion expense within operating expenses in the Consolidated Statements of
+Operations. See Note 10 to our Consolidated Financial Statements.
+Derivatives. We periodically use derivative financial instruments to manage oil and gas price risk
+on a limited amount of our future production and do not use these instruments for trading purposes.
+Settlement of derivative contracts are generally based on the difference between the contract
+price or prices specified in the derivative instrument and a NYMEX price or other cash or futures
+index price. Such derivatives are accounted for under Statement of Financial Accounting Standards
+No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended.
+Our derivative contracts that are accounted for as cash flow hedges under SFAS 133 are recorded at
+fair market value and the changes in fair value are recorded through other comprehensive income
+(loss), net of tax, in stockholders’ equity. The cash settlements on these contracts are recorded
+as an increase or decrease in oil and gas sales. The changes in fair value related to ineffective
+derivative contracts are recognized as derivative expense (income). The cash settlement on these
+contracts is also recorded within derivative expense (income). See Note 8 to our consolidated
+financial statements.
+Share-Based Compensation. Effective January 1, 2006, we adopted Statement of Financial Accounting
+Standard No. 123 (revised 2004), “Share-Based Payment,” (“SFAS 123R”) utilizing the modified
+prospective transition method. Prior to the adoption of SFAS 123R, we accounted for stock option
+grants in accordance with Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued
+to Employees” (the intrinsic value method) and, accordingly, recognized no compensation expense for
+stock option grants.
+Under the modified prospective transition method, SFAS 123R applies to new awards, unvested awards
+as of January 1, 2006 and awards that were outstanding on January 1, 2006 that are subsequently
+modified, repurchased or cancelled. Under the modified prospective transition method, compensation
+cost recognized in 2006 includes compensation cost for all share-based payments granted prior to,
+but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in
+accordance with the original provisions of Statement of Financial Accounting Standard No. 123
+“Accounting for Stock-Based Compensation,” (“SFAS 123”) and compensation cost for all share-based
+payments granted subsequent to January 1, 2006, based on the grant-date fair value estimated in
+accordance with the provisions of SFAS 123R. Prior periods were not restated to reflect the impact
+of adopting the new standard. SFAS 123R also requires the cash flows from tax benefits resulting
+from tax deductions in excess of compensation cost recognized for stock options exercised (excess
+tax benefits) to be classified as financing cash flows. As a result of most of our stock-based
+compensation being in the form of restricted stock, the impact of the adoption of SFAS 123R on
+income before taxes, net income and basic and diluted earnings per share for the year ended
+December 31, 2006 was immaterial. See Note 3 to our consolidated financial statements.
+32 
+Table of Contents 
+New Accounting Standards 
+In September 2006, the FASB issued Statement of Financial Accounting Standard No. 157, (“SFAS
+157”), Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring
+fair value and requires enhanced disclosures about fair value measurements. In February 2007, the
+FASB issued Statement of Financial Accounting Standard No. 159 “The Fair Value Option for Financial
+Assets and Liabilities – Including an amendment of FASB No. 115” (“SFAS 159”). SFAS 159 permits
+entities to choose to measure various financial instruments and certain other items at fair value.
+These statements become effective for us on January 1, 2008. We do not anticipate that the
+implementation of these standards will have a material effect on our consolidated financial
+statements.
+Entrada Acquisition and Development. On April 18, 2007, we completed the acquisition of BP’s 80%
+working interest in the Entrada Field for a purchase price of $190 million. The purchase price
+included $150 million payable at closing and an additional $40 million payable after the
+achievement of certain production milestones. The purchased interests included five federal
+offshore blocks at Garden Banks Blocks 738, 782, 785, 826 and 827, subject to certain depth
+limitations. As a result of the acquisition, we own a 100% working interest in the Entrada field
+and are operator. The acquisition added 150 billion cubic feet of natural gas equivalent (Bcfe) to
+our proved undeveloped reserves.
+The acquisition was recorded at fair value based on the initial purchase price of $150 million. We
+may record the additional $40 million as an additional purchase price in the future when the
+production milestones are achieved, in accordance with the terms of the agreement.
+To finance the initial $150 million payment of the purchase price, we closed on a seven-year $200
+million senior revolving credit facility arranged by Merrill Lynch Capital Corporation
+contemporaneous with the closing of the acquisition. The facility is secured by a lien on the
+Entrada properties. We borrowed the full commitment amount under the facility at closing to cover
+the required $150 million payment to BP and expenses and fees related to the transaction, and the
+balance was used to pay down our UBOC senior secured credit facility.
+In August 2007, we entered into a production handling agreement (“PHA”) with ConocoPhillips and
+Devon Energy Corporation. The PHA provides for production from the Entrada Field to be processed
+through the Magnolia production platform, which is owned by ConocoPhillips and Devon. We also
+entered into a drilling contract with Diamond Offshore Drilling, Inc for the Ocean Victory drilling
+rig to be used to drill and complete two development wells at Entrada. First production is
+expected in the first quarter of 2009.
+Subsequent to December 31, 2007, we entered into an agreement with CIECO to sell 50% of our working
+interest in the Entrada field for a purchase price of $175 million with a cash payment of $155
+million at closing and the additional $20 million payable after the achievement of certain
+production milestones. Additional contingent cash payments could be payable based on
+additional cumulative production milestones. The proceeds from this divestiture along with proceeds from the mineral
+and royalty interest divestiture will be used to fully repay the seven-year $200 million revolving
+credit facility arranged by Merrill Lynch Capital Corporation along with prepayment penalties.
+Also, CIECO has agreed to provide a non-recourse loan of $150 million to assist the financing of
+our 50% share of the $300 million estimated costs to develop the Entrada field. This transaction
+is expected to close in March 2008.
+33 
+Table of Contents 
+Liquidity and Capital Resources 
+Historically, our primary sources of capital have been cash flows from operations, borrowings from
+financial institutions and the sale of debt and equity securities. In December 2007, we completed
+the sale of certain non-core, non-operated royalty and mineral interests for $61.5 million to
+strengthen our balance sheet and provide additional liquidity for the development of our Gulf of
+Mexico deepwater fields, primarily Entrada. Net cash and cash equivalents increased by $51 million
+during 2007 to $53 million. Cash provided from operating activities during 2007 totaled $109
+million, a decrease of 19% from $135 million in 2006.
+On August 30, 2006, we closed on a four-year amended and restated senior secured credit facility
+underwritten by Union Bank of California, N.A. The borrowing base which is reviewed and
+redetermined semi-annually was $50 million at December 31, 2007. There were no borrowings under
+the credit facility at December 31, 2007; however we had a letter of credit outstanding in the
+amount of $15 million to secure a drilling rig for the development of Entrada. See Note 14. As a
+result, $35 million was available for future borrowings under the credit facility as of December
+31, 2007. See Note 7 to our Consolidated Financial Statements.
+In December 2003 and March 2004, we closed on our 9.75% senior notes due 2010 in the aggregate
+principal amount of $200 million. The net proceeds from these notes and the public offering of
+3,450,000 shares of common stock in the second quarter of 2004 were used to restructure our debt
+that was maturing in 2004 and 2005. See Note 7 to the Consolidated Financial Statements for a more
+detailed discussion of long-term debt.
+The indenture governing our 9.75% senior notes due 2010, our senior secured credit facility and our
+senior revolving credit facility contain various covenants including restrictions on additional
+indebtedness and payment of cash dividends. In addition, our senior secured credit facility
+contains covenants for maintenance of certain financial ratios. We were in compliance with these
+covenants at December 31, 2007.
+Our oil and gas reserves as estimated by Huddleston & Co., Inc. were 263.6 Bcfe of natural gas
+equivalent on December 31, 2007. Our cash flow from operations during 2007 was generated by the
+production of 18.7 Bcfe. Production of our reserves during 2008, without weather related downtime,
+is projected to provide sufficient cash flow for a modest capital expenditure program, excluding
+Entrada development, which will be funded from a non-recourse credit facility and proceeds from the
+royalty and mineral interest divestiture.
+Our current planned capital expenditures for 2008, excluding the development cost for the Entrada
+field, total $60 million and include capitalized interest and general and administrative expenses.
+The current portion of our asset retirement obligation will require an additional $11 million
+resulting in capital expenditures of $71 million for 2008. Once the CIECO loan transaction closes,
+we will re-evaluate our capital expenditure plan and consider increasing the drilling portion of
+capital expenditures. The current capital expenditure plans for 2008 include:
+• 
+the discretionary drilling of up to five exploratory and development wells; 
+• 
+lease and seismic acquisition; and 
+• 
+capitalized interest and overhead. 
+We believe that our operating cash flow and our credit facilities will be adequate to meet our
+capital, debt repayment, and operating requirements for 2008. We fund our day-to-day operating
+expenses and capital expenditures from operating cash flow, supplemented as needed by borrowings
+under our credit facilities.
+34 
+Table of Contents 
+In addition, we have sold debt and equity in both public and private offerings in the past,
+and we expect that these sources of capital will continue to be available to us in the future.
+Because of the liquidity and capital resources alternatives available to us, including internally
+generated cash flows, our management believes that our short-term and long-term liquidity is
+adequate to fund operations, including our capital spending program and repayment of maturing debt.
+With regard to the Entrada Field development, we anticipate capital expenditures of approximately
+$120 million, which are expected to be funded by the non-recourse loan from CIECO and the proceeds
+from the royalty and mineral divestiture in 2007.
+Our cash flow, both in the short and long-term, is impacted by highly volatile oil and natural gas
+prices, production levels, industry trends impacting operating expenses and our ability to continue
+to acquire or find reserves at competitive prices. Cash flow forecasts for internal use by
+management are revised monthly in response to changing market conditions and production
+projections. We may adjust capital expenditure budgets within the planned total amount in response
+to the adjusted cash flow forecasts and market trends in drilling and acquisitions costs.
+The following table describes our outstanding contractual obligations as of December 31, 2007 (in
+thousands):
+Payments due by Period 
+More 
+Contractual 
+Less Than 
+One-Three 
+Three-Five 
+Than-Five 
+Obligations 
+Total 
+One Year 
+Years 
+Years 
+Years 
+Senior Secured Credit Facility 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+9.75% Senior Notes 
+200,000 
+— 
+200,000 
+— 
+— 
+Senior Revolving Credit Facility 
+200,000 
+— 
+— 
+— 
+200,000 
+Throughput Commitments: 
+Medusa Spar LLC 
+5,696 
+2,380 
+3,316 
+— 
+— 
+Medusa Oil Pipeline 
+295 
+81 
+113 
+61 
+40 
+$ 
+405,991 
+$ 
+2,461 
+$ 
+203,429 
+$ 
+61 
+$ 
+200,040 
+Off-Balance Sheet Arrangements 
+We have a 10% ownership interest in Medusa Spar LLC (“LLC”), which is a limited liability company
+that owns a 75% undivided ownership interest in the deepwater spar production facilities at our
+Medusa Field in the Gulf of Mexico. We contributed a 15% undivided ownership interest in the
+production facility to the LLC in return for approximately $25 million in cash and a 10% ownership
+interest in the LLC. The LLC earns a tariff based upon production volume throughput from the Medusa
+area. We are obligated to process our share of production from the Medusa Field and any future
+discoveries in the area through the spar production facilities. This arrangement allows us to defer
+the cost of the spar production facility over the life of the Medusa Field. Our cash proceeds were
+used to reduce the balance outstanding under our senior secured credit facility. The LLC used the
+cash proceeds from $83.7 million of non-recourse financing and a cash contribution by one of the
+LLC owners to acquire its 75% interest in the spar. On December 31, 2007, $21.7 million of the
+financing was outstanding. The balance of Medusa Spar LLC is owned by Oceaneering International,
+Inc. and Murphy. We are accounting for our 10% ownership interest in the LLC under the equity
+method.
+35 
+Table of Contents 
+Results of Operations 
+The following table sets forth certain operating information with respect to our oil and gas
+operations for each of the three years in the period ended December 31, 2007.
+December 31, 
+2007 
+2006 
+2005 
+Production: 
+Oil (MBbls) 
+1,063 
+1,634 
+1,837 
+Gas (MMcf) 
+12,340 
+10,977 
+7,768 
+Total production (MMcfe) 
+18,718 
+20,780 
+18,787 
+Average daily production (MMcfe) 
+51.3 
+56.9 
+51.5 
+Average sales price: 
+Oil (per Bbl)(a) 
+$ 
+67.63 
+$ 
+57.33 
+$ 
+41.61 
+Gas (per Mcf) 
+$ 
+8.01 
+$ 
+8.07 
+$ 
+8.35 
+Total (per Mcfe) 
+$ 
+9.12 
+$ 
+8.77 
+$ 
+7.52 
+Oil and gas revenues (in thousands): 
+Oil revenue 
+$ 
+71,891 
+$ 
+93,665 
+$ 
+76,425 
+Gas revenue 
+98,877 
+88,603 
+64,865 
+Total 
+$ 
+170,768 
+$ 
+182,268 
+$ 
+141,290 
+Lease operating expenses (in thousands) 
+$ 
+27,795 
+$ 
+28,881 
+$ 
+24,377 
+Additional per Mcfe data: 
+Sales price 
+$ 
+9.12 
+$ 
+8.77 
+$ 
+7.52 
+Lease operating expenses 
+1.48 
+1.39 
+1.30 
+Operating margin 
+$ 
+7.64 
+$ 
+7.38 
+$ 
+6.22 
+Depletion 
+$ 
+3.89 
+$ 
+3.14 
+$ 
+2.39 
+General and administrative (net of management fees) 
+$ 
+.53 
+$ 
+.41 
+$ 
+.43 
+(a) 
+Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil: 
+Average NYMEX oil price 
+$ 
+72.33 
+$ 
+66.22 
+$ 
+56.57 
+Basis differential and quality adjustments 
+(4.08 
+) 
+(7.03 
+) 
+(8.45 
+) 
+Transportation 
+(1.15 
+) 
+(1.25 
+) 
+(1.26 
+) 
+Hedging 
+0.53 
+(0.61 
+) 
+(5.25 
+) 
+Average realized oil price 
+$ 
+67.63 
+$ 
+57.33 
+$ 
+41.61 
+36 
+Table of Contents 
+Comparison of Results of Operations for the Years Ended December 31, 2007 and 2006 
+Oil and Gas Revenues 
+Total oil and gas revenues decreased 6% from $182.3 million in 2006 to $170.8 million in 2007
+primarily due to lower oil production. Total production on an equivalent basis for 2007 decreased
+by 10% versus 2006.
+Gas production during 2007 totaled 12.3 Bcf and generated $98.9 million in revenues compared to
+11.0 Bcf and $88.6 million in revenues during the same period in 2006. Average gas prices realized
+for 2007 were $8.01 per Mcf compared to $8.07 per Mcf during the same period in 2006. The 12%
+increase in 2007 production was primarily attributable to new discoveries brought on line. The
+increase was partially offset by the sale of the Mobile Bay 952,953,955 Field in the second quarter
+of 2007, early water production from East Cameron Block 90, High Island Block 73 and North Padre
+Island Block 913 and normal and expected declines in production from our High Island Block 119 and
+Mobile Bay area fields and older properties. In addition, remedial work with wireline and coil
+tubing was performed to correct mechanical problems on the A-1 well at Medusa in the fourth quarter
+of 2006 that resulted in production being restored at a lower rate.
+Oil production during 2007 totaled 1,063,000 barrels and generated $71.9 million in revenues
+compared to 1,634,000 barrels and $93.7 million in revenues for the same period in 2006. Average
+oil prices realized in 2007 were $67.63 per barrel compared to $57.33 per barrel in 2006. The 35%
+decrease in production was primarily due to the A-1 well at Medusa having mechanical problems which
+required remedial work in the fourth quarter of 2006 and resulted in production being restored at a
+lower rate. In addition, the #1 well at Habanero became uneconomic as expected in the third
+quarter of 2007 and was sidetracked and completed as planned in an updip location in the reservoir.
+Production from the sidetrack well commenced in October 2007. See the Results of Operations table
+for a reconciliation of the realized oil prices to average NYMEX.
+Lease Operating Expenses 
+Lease operating expenses for 2007 decreased by 4% to $27.8 million compared to $28.9 million for
+the same period in 2006. The decrease was primarily due to the sale of the Mobile Bay 952,953,955
+Field effective May 1, 2007, lower throughput charges at Habanero and the shut-in of our South
+Marsh Island 261 Field, which is scheduled to be plugged and abandoned. The decrease was partially
+offset by additional operating costs associated with our new discoveries.
+Depreciation, Depletion and Amortization 
+Depreciation, depletion and amortization for 2007 and 2006 were $72.8 million and $65.3 million,
+respectively. The 11% increase was due to a higher depletion rate resulting from higher costs
+associated with our exploration and development activities in the Gulf of Mexico.
+Accretion Expense 
+Accretion expense for 2007 and 2006 of $4.0 million and $5.0 million, respectively, represents
+accretion of our asset retirement obligations. See Note 10 to the Consolidated Financial
+Statements.
+37 
+Table of Contents 
+General and Administrative 
+General and administrative expenses for 2007, net of amounts capitalized, were $9.9 million
+compared to $8.6 million in 2006. The 15% increase was a result of additions to our technical staff
+and higher compensation costs.
+Interest Expense 
+Interest expense increased to $34.3 million in 2007 compared to $16.5 million in 2006. This
+increase was due to the new debt associated with the Entrada acquisition. See Notes 7 and 14 for
+more details.
+Income Taxes 
+For 2007, income tax expense was $8.5 million compared to $20.7 million in 2006. The 59% decrease
+was primarily due to a decrease in income before income taxes arising mainly out of the reduced oil
+production and increased interest expense during the year.
+38 
+Table of Contents 
+Comparison of Results of Operations for the Years Ended December 31, 2006 and 2005 Oil and Gas Revenues 
+Total oil and gas revenues increased 29% from $141.3 million in 2005 to $182.3 million in 2006
+primarily due to higher gas production and oil pricing. Total production for 2006 increased by 11%
+versus 2005, which was impacted by downtime for inclement weather.
+Gas production during 2006 totaled 11.0 Bcf and generated $88.6 million in revenues compared to 7.8
+Bcf and $64.9 million in revenues during the same period in 2005. Average gas prices realized for
+2006 were $8.07 per Mcf compared to $8.35 per Mcf during the same period in 2005. The increase in
+production was primarily due to production from our new wells at East Cameron Block 90, North Padre
+Island Block 913, High Island Block 73, Brazos Block 405, West Cameron Block 295, High Island 165
+and West Cameron 3/LA and 2005 production being negatively impacted by inclement weather. The
+increase in production from new properties was partially offset by normal and expected declines in
+production from our Habanero, High Island Block 119 and Mobile Bay area fields and older
+properties.
+Oil production during 2006 totaled 1,634,000 barrels and generated $93.7 million in revenues
+compared to 1,837,000 barrels and $76.4 million in revenues for the same period in 2005. Average
+oil prices realized in 2006 were $57.33 per barrel compared to $41.61 per barrel in 2005. Oil
+production decreased during 2006 primarily due to a normal and expected decline at Habanero. See
+the Results of Operations table for a reconciliation of the realized oil prices to average NYMEX.
+Lease Operating Expenses 
+Lease operating expenses for 2006 increased by 18% to $28.9 million compared to $24.4 million for
+the same period in 2005. The increase was primarily due to new wells coming on line, higher costs
+for fuel and marine transportation and an increase in insurance rates for our policies which were
+renewed on April 1, 2006. In addition, we incurred approximately $1.5 million for pipeline repairs
+at our South Marsh Island Block 261 field and had downhole repairs at our Medusa field.
+Depreciation, Depletion and Amortization 
+Depreciation, depletion and amortization for 2006 and 2005 were $65.3 million and $44.9 million,
+respectively. The 45% increase was due to higher production volumes and a higher average depletion
+rate for 2006 compared to 2005. The higher depletion rate was primarily attributable to higher
+costs associated with our exploration and development activities in the Gulf of Mexico and an
+increase in estimated costs of future development activities and capitalized asset retirement costs
+associated with the future site restoration, dismantlement and abandonment activities.
+Accretion Expense 
+Accretion expense for 2006 and 2005 of $5.0 million and $3.5 million, respectively, represents
+accretion of our asset retirement obligations. The increase was due to the addition of plugging
+and abandonment obligations associated with new discoveries and an increase in plugging and
+abandonment cost estimates. See Note 10 to the Consolidated Financial Statements.
+39 
+Table of Contents 
+General and Administrative 
+General and administrative expenses for 2006, net of amounts capitalized, were $8.6 million
+compared to $8.1 million in 2005. We recognized non-cash charges of approximately $1.1 million in
+the third quarter of 2006 for the vesting of 20% of restricted shares granted in August 2006.
+General and administrative expenses for 2005 included non-cash charges of $930,000 recognized in
+the second quarter of 2005 for the accelerated vesting of performance shares pursuant to the terms
+of the plan due to deaths or disability for an executive officer and two directors of the Company.
+See Note 3 for more details.
+Interest Expense 
+Interest expense was relatively consistent in 2006 in the amount of $16.5 million compared to $16.7
+million in 2005.
+Income Taxes 
+For 2006, we had income tax expense of $20.7 million compared to $13.2 million in 2005. The 57%
+increase was primarily due to an increase in income before income taxes.
+40 
+Table of Contents 
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS 
+Commodity Price Risk 
+The Company’s revenues are derived from the sale of its crude oil and natural gas production. The
+prices for oil and gas remain extremely volatile and sometimes experience large fluctuations as a
+result of relatively small changes in supply, weather conditions, economic conditions and
+government actions. From time to time, the Company enters into derivative financial instruments to
+manage oil and gas price risk.
+The Company may utilize fixed price “swaps”, which reduce the Company’s exposure to decreases in
+commodity prices and limit the benefit the Company might otherwise have received from any increases
+in commodity prices.
+The Company may utilize price “collars” to reduce the risk of changes in oil and gas prices. Under
+these arrangements, no payments are due by either party as long as the market price is above the
+floor price and below the ceiling price set in the collar. If the price falls below the floor, the
+counter-party to the collar pays the difference to the Company, and if the price rises above the
+ceiling, the counter-party receives the difference from the Company.
+Callon may purchase “puts” which reduce the Company’s exposure to decreases in oil and gas prices
+while allowing realization of the full benefit from any increases in oil and gas prices. If the
+price falls below the floor, the counter-party pays the difference to the Company.
+The Company enters into these various agreements from time to time to reduce the effects of
+volatile oil and gas prices and does not enter into derivative transactions for speculative
+purposes. However, certain of the Company’s derivative positions may not be designated as hedges
+for accounting purposes. See Note 8 to the Consolidated Financial Statements for a description of
+the Company’s hedged position at December 31, 2007.
+Based on projected annual sales volumes for 2008 (excluding incremental production from 2007
+exploratory drilling), a 10% decline in the prices Callon receives for its crude oil and natural
+gas production would have an approximate $15 million impact on our revenues.
+Interest Rate Risk 
+The Company’s $200 million senior revolving credit facility arranged by Merrill Lynch Capital
+Corporation bears interest at a variable LIBOR-based rate. As a result, an increase in LIBOR would
+increase the interest cost associated with this facility and would have a negative impact on the
+Company’s results of operations and cash flows. As of December 31, 2007, the Company had $200
+million of borrowings outstanding under the facility and had an interest rate swap in place to
+reduce its risk associated with changes in interest rates on $25 million of this variable rate debt
+for a remaining period of three months. See Note 8 to the consolidated financial statements for a
+description of the interest rate hedge and Note 7 for the Company’s outstanding debt at December
+31, 2007.
+41 
+Table of Contents 
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+Page 
+Report of Independent Registered Public Accounting Firm 
+43 
+Consolidated Balance Sheets as of December 31, 2007
+and 2006 
+44 
+Consolidated Statements of Operations for Each of the Three Years
+in the Period Ended December 31, 2007 
+45 
+Consolidated Statements of Stockholders’ Equity
+for Each of the Three Years in the Period Ended December 31, 2007 
+46 
+Consolidated Statements of Cash Flows for Each of the Three Years
+in the Period Ended December 31, 2007 
+47 
+Notes to Consolidated Financial Statements 
+48 
+42 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm
+The Board of Directors and Stockholders of 
+Callon Petroleum Company
+We have audited the accompanying consolidated balance sheets of Callon Petroleum Company as of
+December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’
+equity and cash flows for each of the three years in the period ended December 31, 2007. These
+financial statements are the responsibility of the Company’s management. Our responsibility is to
+express an opinion on these financial statements based on our audits.
+We conducted our audits in accordance with the standards of the Public Company Accounting
+Oversight Board (United States). Those standards require that we plan and perform the audit to
+obtain reasonable assurance about whether the financial statements are free of material
+misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
+disclosures in the financial statements. An audit also includes assessing the accounting
+principles used and significant estimates made by management, as well as evaluating the overall
+financial statement presentation. We believe that our audits provide a reasonable basis for our
+opinion.
+In our opinion, the financial statements referred to above present fairly, in all material
+respects, the consolidated financial position of Callon Petroleum Company as of December 31, 2007
+and 2006, and the consolidated results of its operations and its cash flows for each of the three
+years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting
+principles.
+As discussed in Note 2 to the financial statements, in 2007 the Company changed its method of
+accounting for income taxes and in 2006 the Company changed its method of accounting for
+stock-based compensation.
+We also have audited, in accordance with the standards of the Public Company Accounting
+Oversight Board (United States), Callon Petroleum Company’s internal control over financial
+reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated
+Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our
+report dated March 13, 2008, expressed an unqualified opinion thereon.
+/s/ Ernst & Young LLP
+New Orleans, Louisiana 
+March 13, 2008
+43 
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED BALANCE SHEETS 
+(In thousands, except share data) 
+December 31, 
+2007 
+2006 
+ASSETS 
+Current assets: 
+Cash and cash equivalents 
+$ 
+53,250 
+$ 
+1,896 
+Accounts receivable 
+22,073 
+32,166 
+Restricted investments 
+100 
+4,306 
+Fair market value of derivatives 
+— 
+13,311 
+Other current assets 
+6,592 
+5,973 
+Total current assets 
+82,015 
+57,652 
+Oil and gas properties, full-cost accounting method: 
+Evaluated properties 
+1,349,904 
+1,096,907 
+Less accumulated depreciation, depletion and amortization 
+(738,374 
+) 
+(604,682 
+) 
+611,530 
+492,225 
+Unevaluated properties excluded from amortization 
+70,176 
+54,802 
+Total oil and gas properties 
+681,706 
+547,027 
+Other property and equipment, net 
+1,986 
+1,996 
+Restricted investments 
+4,525 
+1,935 
+Investment in Medusa Spar LLC 
+12,673 
+12,580 
+Other assets, net 
+9,577 
+4,337 
+Total assets 
+$ 
+792,482 
+$ 
+625,527 
+LIABILITIES AND STOCKHOLDERS’ EQUITY 
+Current liabilities: 
+Accounts payable and accrued liabilities 
+$ 
+37,698 
+$ 
+46,611 
+Asset retirement obligations 
+9,810 
+14,355 
+Fair market value of derivatives 
+5,205 
+— 
+Current maturities of long-term debt 
+— 
+213 
+Total current liabilities 
+52,713 
+61,179 
+Long-term debt 
+392,012 
+225,521 
+Asset retirement obligations 
+27,027 
+26,824 
+Deferred tax liability 
+32,190 
+30,054 
+Other long-term liabilities 
+1,465 
+586 
+Total liabilities 
+505,407 
+344,164 
+Stockholders’ equity: 
+Preferred Stock, $.01 par value; 2,500,000 shares authorized; 
+— 
+— 
+Common Stock, $.01 par value; 30,000,000 shares
+authorized; 20,891,145 shares and 20,747,773 shares issued
+outstanding at December 31, 2007 and 2006, respectively 
+209 
+207 
+Capital in excess of par value 
+223,336 
+220,785 
+Other comprehensive income (loss) 
+(3,383 
+) 
+8,652 
+Retained earnings 
+66,913 
+51,719 
+Total stockholders’ equity 
+287,075 
+281,363 
+Total liabilities and stockholders’ equity 
+$ 
+792,482 
+$ 
+625,527 
+The accompanying notes are an integral part of these financial statements.
+44 
+Table of Contents 
+Callon Petroleum Company 
+Consolidated Statements of Operations 
+For the Years Ended December 31, 2007, 2006 and 2005 
+(In thousands, except per share amounts) 
+2007 
+2006 
+2005 
+Operating revenues: 
+Oil sales 
+$ 
+71,891 
+$ 
+93,665 
+$ 
+76,425 
+Gas sales 
+98,877 
+88,603 
+64,865 
+Total operating revenues 
+170,768 
+182,268 
+141,290 
+Operating expenses: 
+Lease operating expenses 
+27,795 
+28,881 
+24,377 
+Depreciation, depletion and amortization 
+72,762 
+65,283 
+44,946 
+General and administrative 
+9,876 
+8,591 
+8,085 
+Accretion expense 
+3,985 
+4,960 
+3,549 
+Derivative expense 
+— 
+150 
+6,028 
+Total operating expenses 
+114,418 
+107,865 
+86,985 
+Income from operations 
+56,350 
+74,403 
+54,305 
+Other (income) expenses: 
+Interest expense 
+34,329 
+16,480 
+16,660 
+Other income 
+(1,172 
+) 
+(1,869 
+) 
+(998 
+) 
+Total other (income) expenses 
+33,157 
+14,611 
+15,662 
+Income before income taxes 
+23,193 
+59,792 
+38,643 
+Income tax expense 
+8,506 
+20,707 
+13,209 
+Income before equity in earnings of Medusa Spar LLC 
+14,687 
+39,085 
+25,434 
+Equity in earnings of Medusa Spar LLC, net of tax 
+507 
+1,475 
+1,342 
+Net income 
+15,194 
+40,560 
+26,776 
+Preferred stock dividends 
+— 
+— 
+318 
+Net income available to common shares 
+$ 
+15,194 
+$ 
+40,560 
+$ 
+26,458 
+Net income per common share: 
+Basic 
+$ 
+0.73 
+$ 
+2.00 
+$ 
+1.43 
+Diluted 
+$ 
+0.71 
+$ 
+1.90 
+$ 
+1.28 
+Shares used in computing net income per share amounts: 
+Basic 
+20,776 
+20,270 
+18,453 
+Diluted 
+21,290 
+21,363 
+20,883 
+The accompanying notes are an integral part of these financial statements.
+45 
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY 
+(In thousands) 
+Unearned 
+Accumulated 
+Total 
+Restricted 
+Capital in 
+Other 
+Retained 
+Stock- 
+Preferred 
+Common 
+Stock 
+Excess of 
+Comprehensive 
+Earnings 
+holders’ 
+Stock 
+Stock 
+Compensation 
+Par Value 
+Income (Loss) 
+(Deficit) 
+Equity 
+Balances, December 31, 2004 
+$ 
+6 
+$ 
+176 
+$ 
+(5,352 
+) 
+$ 
+220,664 
+$ 
+(1,883 
+) 
+$ 
+(15,299 
+) 
+$ 
+198,312 
+Comprehensive income: 
+Net income 
+— 
+— 
+— 
+— 
+— 
+26,776 
+Other comprehensive income 
+— 
+— 
+— 
+— 
+1,552 
+— 
+Total comprehensive income 
+28,328 
+Preferred stock dividend 
+— 
+— 
+— 
+— 
+— 
+(318 
+) 
+(318 
+) 
+Conversion of preferred shares
+to common stock 
+(6 
+) 
+13 
+— 
+(643 
+) 
+— 
+— 
+(636 
+) 
+Shares issued pursuant to employee
+benefit and option plan 
+— 
+1 
+— 
+(325 
+) 
+— 
+— 
+(324 
+) 
+Employee stock purchase plan 
+— 
+— 
+— 
+(33 
+) 
+— 
+— 
+(33 
+) 
+Tax benefits related to stock
+compensation plans 
+— 
+— 
+— 
+1,029 
+— 
+— 
+1,029 
+Restricted stock 
+— 
+2 
+2,018 
+(330 
+) 
+— 
+— 
+1,690 
+Warrants 
+— 
+2 
+— 
+(2 
+) 
+— 
+— 
+— 
+Balances, December 31, 2005 
+— 
+194 
+(3,334 
+) 
+220,360 
+(331 
+) 
+11,159 
+228,048 
+Comprehensive income: 
+Net income 
+— 
+— 
+— 
+— 
+— 
+40,560 
+Other comprehensive income 
+— 
+— 
+— 
+— 
+8,983 
+— 
+Total comprehensive income 
+49,543 
+Shares issued pursuant to employee
+benefit and option plan 
+— 
+2 
+— 
+(441 
+) 
+— 
+— 
+(439 
+) 
+Tax benefits related to stock
+compensation plans 
+— 
+— 
+— 
+1,356 
+— 
+— 
+1,356 
+Adoption of 123R 
+3,334 
+(3,334 
+) 
+— 
+— 
+— 
+Restricted stock 
+— 
+1 
+— 
+2,854 
+— 
+— 
+2,855 
+Warrants 
+— 
+10 
+— 
+(10 
+) 
+— 
+— 
+— 
+Balances, December 31, 2006 
+$ 
+— 
+$ 
+207 
+$ 
+— 
+$ 
+220,785 
+$ 
+8,652 
+$ 
+51,719 
+$ 
+281,363 
+Comprehensive income: 
+Net income 
+— 
+— 
+— 
+— 
+— 
+15,194 
+Other comprehensive income 
+— 
+— 
+— 
+— 
+(12,035 
+) 
+— 
+Total comprehensive income 
+3,159 
+Shares issued pursuant to employee
+benefit and option plan 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+Tax benefits related to stock
+compensation plans 
+— 
+— 
+— 
+163 
+— 
+— 
+163 
+Restricted stock 
+— 
+2 
+— 
+2,388 
+— 
+— 
+2,390 
+Balances, December 31, 2007 
+$ 
+— 
+$ 
+209 
+$ 
+— 
+$ 
+223,336 
+$ 
+(3,383 
+) 
+$ 
+66,913 
+$ 
+287,075 
+The accompanying notes are an integral part of these financial statements.
+46 
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+For the Years Ended December 31, 2007, 2006 and 2005 
+(In thousands) 
+2007 
+2006 
+2005 
+Cash flows from operating activities: 
+Net income 
+$ 
+15,194 
+$ 
+40,560 
+$ 
+26,776 
+Adjustments to reconcile net income to
+cash provided by operating activities: 
+Depreciation, depletion and amortization 
+73,677 
+65,929 
+45,657 
+Accretion expense 
+3,985 
+4,960 
+3,549 
+Amortization of deferred financing costs 
+3,009 
+2,221 
+2,062 
+Equity in earnings of Medusa Spar, LLC 
+(507 
+) 
+(1,475 
+) 
+(1,342 
+) 
+Non-cash derivative expense 
+— 
+150 
+1,635 
+Deferred income tax expense 
+8,506 
+20,707 
+13,209 
+Non-cash charge related to compensation plans 
+849 
+1,420 
+1,906 
+Excess tax benefits from share-based payment arrangements 
+(163 
+) 
+(1,449 
+) 
+— 
+Changes in current assets and liabilities: 
+Accounts receivable 
+6,658 
+(2,107 
+) 
+(11,169 
+) 
+Other current assets 
+(619 
+) 
+(3,975 
+) 
+670 
+Current liabilities 
+(2,057 
+) 
+11,311 
+(8,666 
+) 
+Change in gas balancing receivable 
+(938 
+) 
+(311 
+) 
+322 
+Change in gas balancing payable 
+889 
+133 
+(289 
+) 
+Change in other long-term liabilities 
+(10 
+) 
+(2 
+) 
+(18 
+) 
+Change in other assets, net 
+810 
+(2,588 
+) 
+(292 
+) 
+Cash provided by operating activities 
+109,283 
+135,484 
+74,010 
+Cash flows from investing activities: 
+Capital expenditures 
+(127,409 
+) 
+(167,979 
+) 
+(73,072 
+) 
+Entrada acquisition 
+(150,000 
+) 
+— 
+— 
+Proceeds from sale of mineral interests 
+60,931 
+— 
+— 
+Distribution from Medusa Spar, LLC 
+687 
+1,078 
+463 
+Cash used by investing activities 
+(215,791 
+) 
+(166,901 
+) 
+(72,609 
+) 
+Cash flows from financing activities: 
+Change in accrued liabilities to be refinanced 
+— 
+(5,000 
+) 
+5,000 
+Increases in debt 
+229,000 
+88,000 
+7,000 
+Payments on debt 
+(64,000 
+) 
+(53,000 
+) 
+(12,000 
+) 
+Deferred financing costs 
+(6,429 
+) 
+— 
+— 
+Issuance of common stock 
+— 
+— 
+2 
+Buyout of preferred stock 
+— 
+— 
+(637 
+) 
+Equity issued related to employee stock plans 
+— 
+(438 
+) 
+(573 
+) 
+Excess tax benefits from share-based payment arrangements 
+163 
+1,449 
+— 
+Capital leases 
+(872 
+) 
+(263 
+) 
+(576 
+) 
+Cash dividends on preferred stock 
+— 
+— 
+(318 
+) 
+Cash provided (used) by financing activities 
+157,862 
+30,748 
+(2,102 
+) 
+Net increase (decrease) in cash and cash equivalents 
+51,354 
+(669 
+) 
+(701 
+) 
+Cash and cash equivalents: 
+Balance, beginning of period 
+1,896 
+2,565 
+3,266 
+Balance, end of period 
+$ 
+53,250 
+$ 
+1,896 
+$ 
+2,565 
+The accompanying notes are an integral part of these financial statements.
+47 
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+1. ORGANIZATION 
+General 
+Callon Petroleum Company (“the Company” or “Callon”) was organized under the laws of the state of
+Delaware in March 1994 to serve as the surviving entity in the consolidation and combination of
+several related entities (referred to herein collectively as the “Constituent Entities”). The
+combination of the businesses and properties of the Constituent Entities with the Company was
+completed on September 16, 1994 (“Consolidation”).
+As a result of the Consolidation, all of the businesses and properties of the Constituent Entities
+are owned (directly or indirectly) by the Company. Certain registration rights were granted to the
+stockholders of certain of the Constituent Entities. See Note 9.
+The Company and its predecessors have been engaged in the acquisition, development and exploration
+of crude oil and natural gas since 1950. The Company’s properties are geographically concentrated
+in Louisiana and offshore Gulf of Mexico.
+2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 
+Principles of Consolidation and Reporting 
+The Consolidated Financial Statements include the accounts of the Company, and its subsidiary,
+Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries, namely Callon Offshore
+Production, Inc. and Mississippi Marketing, Inc. All intercompany accounts and transactions have
+been eliminated. Certain prior year amounts have been reclassified to conform to presentation in
+the current year.
+Use of Estimates 
+The preparation of financial statements in conformity with U.S. generally accepted accounting
+principles requires management to make estimates and assumptions that affect the reported amounts
+of assets and liabilities and disclosure of contingent assets and liabilities at the date of the
+financial statements and the reported amounts of revenues and expenses during the reporting period.
+Actual results could differ from those estimates.
+Asset Retirement Obligations 
+The Company accounts for asset retirement obligations in accordance with Statement of Financial
+Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), which
+essentially requires entities to record the fair value of a liability for obligations associated
+with the retirement of tangible long-lived assets and the associated asset retirement costs.
+Interest is accreted on the present value of the asset retirement obligation and reported as
+accretion expense within operating expenses in the consolidated statements of operations. See Note
+10.
+48 
+Table of Contents 
+Oil and Gas Properties 
+The Company follows the full-cost method of accounting for oil and gas properties whereby all costs
+incurred in connection with the acquisition, exploration and development of oil and gas reserves,
+including certain overhead costs, are capitalized. Such amounts include the cost of drilling and
+equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest
+capitalized on unevaluated leases, other costs related to exploration and development activities,
+and site restoration, dismantlement and abandonment costs capitalized under SFAS 143. General and
+administrative costs capitalized include salaries and related fringe benefits paid to employees
+directly engaged in the acquisition, exploration and/or development of oil and gas properties as
+well as other directly identifiable general and administrative costs associated with such
+activities. Such capitalized costs ($10.8 million in 2007, $9.6 million in 2006 and $7.1 million in
+2005) do not include any costs related to production or general corporate overhead. Costs
+associated with unevaluated properties, including capitalized interest on such costs, are excluded
+from amortization. Unevaluated property costs are transferred to evaluated property costs at such
+time as wells are completed on the properties or management determines that these costs have been
+impaired.
+Costs of oil and gas properties, including future development costs, which have proved reserves and
+properties which have been determined to be worthless, are depleted using the unit-of-production
+method based on proved reserves. If the total capitalized costs of oil and gas properties, net of
+accumulated amortization and deferred taxes relating to oil and gas properties, exceed the sum of
+(1) the estimated future net revenues from proved reserves at current prices discounted at 10% and
+(2) the lower of cost or market of unevaluated properties, net of tax effects (the full-cost
+ceiling amount), then such excess is charged to expense during the period in which the excess
+occurs. See Note 11.
+Upon the acquisition or discovery of oil and gas properties, management estimates the future net
+costs to be incurred to dismantle, abandon and restore the property using available geological,
+engineering and regulatory data. Such cost estimates are periodically updated for changes in
+conditions and requirements. In accordance with SFAS 143, such costs are capitalized to the
+full-cost pool when the related liabilities are incurred. In accordance with SEC Staff Accounting
+Bulletin No. 106, assets recorded in connection with the recognition of an asset retirement
+obligation pursuant to SFAS 143 are included as part of the costs subject to the full-cost ceiling
+limitation. The future cash outflows associated with settling the recorded asset retirement
+obligations are excluded from the computation of the present value of estimated future net revenues
+used in determining the full-cost ceiling amount.
+Property and Equipment 
+Depreciation of other property and equipment is provided using the straight-line method over
+estimated lives of three to 20 years. Depreciation of pipeline and other facilities is provided
+using the straight-line method over estimated lives of 15 to 27 years. Depreciation expense of
+$457,000, $351,000 and $355,000 relating to other property and equipment was included in general
+and administrative expenses in the Company’s consolidated statements of operations for the years
+ended December 31, 2007, 2006 and 2005, respectively. The accumulated depreciation on other
+property and equipment was $11.2 million and $10.8 million as of December 31, 2007 and 2006,
+respectively.
+49 
+Table of Contents 
+Investment in Medusa Spar LLC 
+The Company has a 10% ownership interest in Medusa Spar, LLC (“LLC”), which is a limited liability
+company that owns a 75% undivided ownership interest in the deepwater spar production facilities on
+Callon’s Medusa Field in the Gulf of Mexico. The Company contributed a 15% undivided ownership
+interest in the production facility to the LLC in return for approximately $25 million in cash and
+a 10% ownership interest in the LLC. The LLC earns a tariff based upon production volume throughput
+from the Medusa area. Callon is obligated to process its share of production from the Medusa Field
+and any future discoveries in the area through the spar production facilities. This arrangement
+allows Callon to defer the cost of the spar production facility over the life of the Medusa Field.
+The Company’s cash proceeds were used to reduce the balance outstanding under its senior secured
+credit facility. The LLC used the cash proceeds from $83.7 million of non-recourse financing and a
+cash contribution by one of the LLC owners to acquire its 75% interest in the spar. On December 31,
+2007, $21.7 million of the financing was outstanding. The balance of Medusa Spar LLC is owned by
+Oceaneering International, Inc. (NYSE:OII) and Murphy Oil Corporation (NYSE:MUR). The Company is
+accounting for its 10% ownership interest in the LLC under the equity method.
+Natural Gas Imbalances 
+The Company follows the entitlement method of accounting for its proportionate share of gas
+production on a well-by-well basis, recording a receivable to the extent that a well is in an
+“undertake” position and recording a liability to the extent that a well is in an “overtake”
+position. Gas balancing receivables were $1.7 million and $714,000 as of December 31, 2007 and
+2006, respectively. Gas balancing payables were $1.3 million and $437,000 as of December 31, 2007
+and 2006, respectively.
+Derivatives 
+The Company periodically uses derivative financial instruments to manage oil and gas price risk on
+a limited amount of its future production and does not use these instruments for trading purposes.
+Settlement of derivative contracts is generally based on the difference between the contract price
+or prices specified in the derivative instrument and a NYMEX price or other cash or futures index
+price. Such derivatives are accounted for under Statement of Financial Accounting Standards No.
+133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended.
+The Company’s derivative contracts that are accounted for as cash flow hedges under SFAS 133 are
+recorded at fair market value and the changes in fair value are recorded through other
+comprehensive income (loss), net of tax, in stockholders’ equity. The cash settlements on these
+contracts are recorded as an increase or decrease in oil and gas sales. The changes in fair value
+related to ineffective derivative contracts are recognized as derivative expense (income). The
+cash settlement on these contracts is also recorded within derivative expense (income). See Note
+8.
+50 
+Table of Contents 
+Income Taxes 
+The Company accounts for income taxes in accordance with Statement of Financial Accounting
+Standards No. 109, “Accounting for Income Taxes” (“SFAS 109”). Provisions for income taxes include
+deferred taxes resulting primarily from temporary differences due to different reporting methods
+for oil and gas properties for financial reporting purposes and income tax purposes. SFAS 109
+provides for the recognition of a deferred tax asset for net operating loss carryforwards,
+statutory depletion carryforward and tax credit carryforwards, net of a valuation allowance. The
+valuation allowance is provided for that portion of the asset for which it is deemed more likely
+than not will not be realized.
+Callon adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48 “Accounting for
+Uncertainty in Income Taxes” (“FIN 48”), effective January 1, 2007. FIN 48 clarifies the
+accounting for income taxes by prescribing the minimum recognition threshold a tax position is
+required to meet before being recognized in the financial statements. FIN 48 also provides
+guidance on derecognition, measurement, classification, interest and penalties, and disclosure.
+See Note 5.
+Stock-Based Compensation 
+Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standard No. 123
+(revised 2004), “Share-Based Payment,” (“SFAS 123R”) utilizing the modified prospective transition
+method. Prior to the adoption of SFAS 123R, the Company accounted for stock option grants in
+accordance with Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to
+Employees” (the intrinsic value method) and, accordingly, recognized no compensation expense for
+stock option grants.
+Under the modified prospective transition method, SFAS 123R applies to new awards, unvested awards
+as of January 1, 2006 and awards that were outstanding on January 1, 2006 that are subsequently
+modified, repurchased or cancelled. Under the modified prospective transition method, compensation
+cost recognized in 2007 and 2006 includes compensation cost for all share-based payments granted
+prior to, but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in
+accordance with the original provisions of Statement of Financial Accounting Standard No. 123
+“Accounting for Stock-Based Compensation,” (“SFAS 123”) and compensation cost for all share-based
+payments granted subsequent to January 1, 2006, based on the grant-date fair value estimated in
+accordance with the provisions of SFAS 123R. Prior periods were not restated to reflect the impact
+of adopting the new standard.
+SFAS 123R requires the cash flows from tax benefits resulting from tax deductions in excess of
+compensation cost recognized for stock options exercised (excess tax benefits) to be classified as
+financing cash flows. The $163,000 and $1.4 million of excess tax benefits classified as a
+financing cash inflow for the years ended December 31, 2007 and 2006, respectively would have been
+classified as an operating cash flow had the Company not adopted SFAS 123R. There were no stock
+option exercises in the year ended December 31, 2007 and no cash proceeds from the exercise of
+stock options for the year ended December 31, 2006 due to the fact that all options were exercised
+through net-share settlements. As a result of most of the Company’s stock-based compensation being
+in the form of restricted stock, the impact of the adoption of SFAS 123R on income before taxes,
+net income and basic and diluted earnings per share for the year ended December 31, 2006 was not
+significant. See Note 3.
+51 
+Table of Contents 
+Accounts Receivable 
+Accounts receivable consists primarily of accrued oil and gas production receivables. The balance
+in the reserve for doubtful accounts netted within accounts receivable was $65,000 and $66,000 at
+December 31, 2007 and 2006, respectively. There were net charge offs of $1,000 recorded against
+the reserve for doubtful accounts and no provisions to expense in the three-year period ended
+December 31, 2007.
+Major Customers 
+The Company’s production is generally sold on month-to-month contracts at prevailing prices. The
+following table identifies customers to whom it sold a significant percentage of its total oil and
+gas production during each of the years ended:
+December 31, 
+2007 
+2006 
+2005 
+Shell Trading Company 
+25 
+% 
+41 
+% 
+34 
+% 
+Louis Dreyfus Energy Services 
+20 
+% 
+25 
+% 
+16 
+% 
+StatoilHydro 
+13 
+% 
+— 
+— 
+Plains Marketing, L.P. 
+10 
+% 
+11 
+% 
+16 
+% 
+Walter Oil and Gas Corporation 
+8 
+% 
+— 
+— 
+Chevron Texaco Natural Gas 
+— 
+3 
+% 
+10 
+% 
+Because alternative purchasers of oil and gas are readily available, the Company believes that the
+loss of any of these purchasers would not result in a material adverse effect on its ability to
+market future oil and gas production.
+Statements of Cash Flows 
+The Company considers all highly liquid investments with an original maturity of three months or
+less to be cash equivalents.
+The Company paid no federal income taxes for the three years in the period ended December 31, 2007.
+During the years ended December 31, 2007, 2006 and 2005, the Company made cash payments for
+interest of $37.6 million, $20.5 million and $19.9 million, respectively.
+Fair Value of Financial Instruments 
+Fair value of cash and cash equivalents, accounts receivable and accounts payable, approximated
+book value at December 31, 2007 and 2006. The fair value of the senior revolving credit facility
+approximated book value at December 31, 2007. The senior secured credit facility and capital lease
+had no balance outstanding at December 31, 2007 and the fair value approximated book value at
+December 31, 2006. The Company’s 9.75% Senior Notes due 2010 had an estimated fair value of 94%
+and 101.5% of face value at December 31, 2007 and 2006, respectively.
+52 
+Table of Contents 
+Accounting Pronouncements 
+In September 2006, the FASB issued Statement of Financial Accounting Standard No. 157, (“SFAS
+157”), Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring
+fair value and requires enhanced disclosures about fair value measurements. In February 2007, the
+FASB issued Statement of Financial Accounting Standard No. 159 “The Fair Value Option for Financial
+Assets and Liabilities – Including an amendment of FASB No. 115” (“SFAS 159”). SFAS 159 permits
+entities to choose to measure various financial instruments and certain other items at fair value.
+These statements became effective for the Company on January 1, 2008. The Company does not
+anticipate that the implementation of these new standards will have a material effect on its
+consolidated financial statements.
+3. STOCK-BASED COMPENSATION 
+The Company has various stock plans (“Plans”) under which employees of the Company and its
+subsidiaries and non-employee members of the Board of Directors of the Company have been or may be
+granted certain stock-based compensation. For further discussion of the Plans, refer to Note 12.
+For the year ended December 31, 2007, the Company recorded stock-based compensation expense of $2.9
+million, of which $1.4 million was included in general and administrative expenses and $1.5 million
+was capitalized to oil and gas properties. For the year ended
+December 31, 2006, the Company recorded stock-based compensation
+expense of $3.5 million, of which $1.8 million was included in
+general and administrative expenses and $1.7 million was capitalized
+to oil and gas properties. Shares available for future stock option or restricted
+stock grants to employees and directors under existing plans were 436,142 at December 31, 2007.
+The following table illustrates the effect on operating results and net income per share had the
+Company accounted for stock-based compensation in accordance with SFAS 123 for the year ended
+December 31, 2005:
+Year Ended December 31, 2005 
+(In thousands, except per share data) 
+Net income available to common shares,
+as reported 
+$ 
+26,458 
+Stock-based compensation expense included
+in net income as reported, net of tax 
+1,313 
+Deduct: Total stock-based
+compensation expense under fair
+value based method, net of tax 
+(1,497 
+) 
+Pro forma net income available to
+common shares 
+$ 
+26,274 
+Basic net income per share: 
+As Reported 
+1.43 
+Pro Forma 
+1.42 
+Diluted net income per share: 
+As Reported 
+1.28 
+Pro Forma 
+1.27 
+53 
+Table of Contents 
+Stock Options 
+The Company uses the Black-Scholes option pricing model to estimate the fair value of stock option
+awards with the following weighted-average assumptions for the indicated periods.
+Years Ended 
+December 31, 
+2007 
+2006 
+2005 
+Dividend yield 
+— 
+— 
+— 
+Expected volatility 
+36.2 
+% 
+38.9 
+% 
+37.5 
+% 
+Risk-free interest rate 
+4.7 
+% 
+4.6 
+% 
+4.3 
+% 
+Expected life of option (in years) 
+5 
+5 
+5 
+Weighted-average grant-date fair value 
+$ 
+5.64 
+$ 
+7.72 
+$ 
+5.93 
+Forfeiture rate 
+2.0 
+% 
+7.5 
+% 
+— 
+The assumptions above are based on multiple factors, including historical exercise patterns of
+employees with respect to exercise and post-vesting employment termination behaviors, expected
+future exercising patterns and the historical volatility of the Company’s stock price.
+The following table represents stock option activity for the three years ended December 31, 2007:
+2007 
+2006 
+2005 
+Wtd Avg 
+Wtd Avg 
+Wtd Avg 
+Shares 
+Ex Price 
+Shares 
+Ex Price 
+Shares 
+Ex Price 
+Outstanding, beginning of year 
+740,225 
+$ 
+9.93 
+1,205,558 
+$ 
+10.11 
+1,512,599 
+$ 
+9.93 
+Granted (at market) 
+30,000 
+14.27 
+15,000 
+18.69 
+65,000 
+15.79 
+Exercised 
+— 
+— 
+(480,333 
+) 
+10.66 
+(329,441 
+) 
+10.34 
+Forfeited 
+— 
+— 
+— 
+— 
+— 
+— 
+Expired 
+(15,000 
+) 
+15.31 
+— 
+— 
+(42,600 
+) 
+10.60 
+Outstanding, end of year 
+755,225 
+$ 
+10.00 
+740,225 
+$ 
+9.93 
+1,205,558 
+$ 
+10.11 
+Exercisable, end of year 
+710,225 
+$ 
+9.57 
+695,225 
+$ 
+9.44 
+1,166,558 
+$ 
+9.88 
+Weighted-average remaining 
+Contract life: 
+Outstanding options
+at end of period 
+3.39 yrs. 
+4.06 yrs. 
+3.98 yrs. 
+Outstanding
+exercisable at end of period 
+3.08 yrs. 
+3.76 yrs. 
+3.79 yrs. 
+As of December 31, 2007, the aggregate intrinsic value of options outstanding was $5.0 million and
+the aggregate intrinsic value of options exercisable was
+$4.9 million. As of December 31, 2006, the aggregate intrinsic
+value of options outstanding was $3.9 million and the aggregate
+intrinsic value of options exercisable was $3.9 million. Total
+intrinsic value of options exercised was $4.1 million for the year
+ended December 31, 2006. At December 31, 2007, there
+was $218,000 of unrecognized compensation cost related to nonvested stock options, which is
+expected to be recognized over a weighted-average period of two years.
+54 
+Table of Contents 
+Restricted Stock 
+The Plans allow for the issuance of restricted stock awards. The unearned stock-based compensation
+related to these awards is being amortized to compensation expense on a straight-line basis over
+the requisite service period for the entire award. The compensation expense for these awards was
+determined based on the market price of our stock at the date of grant applied to the total numbers
+of shares that were anticipated to fully vest. As of December 31, 2007, there was $6.4 million of
+unrecognized compensation cost associated with these awards, which is expected to be recognized
+over a weighted average period of 2.3 years.
+The following table represents unvested restricted stock activity for the year ended December 31,
+2007:
+Weighted-Average 
+Number of 
+Grant-Date 
+Shares 
+Fair Value 
+Outstanding shares at beginning of period 
+658,800 
+$ 
+15.13 
+Granted 
+10,000 
+14.54 
+Vested 
+(181,350 
+) 
+14.99 
+Forfeited 
+— 
+— 
+Outstanding shares at end of period 
+487,450 
+$ 
+15.17 
+For the years ended December 31, 2007, 2006 and 2005 the Company recognized non-cash compensation
+expense associated with the restricted stock awards of $2.7 million, $3.4 million and $2.0 million,
+respectively. Included in 2005 was $1.0 million of accelerated vesting of performance shares
+pursuant to the terms of the plan due to the deaths or disability for an executive officer and two
+directors of the Company.
+55 
+Table of Contents 
+4. NET INCOME PER SHARE 
+Basic net income per common share was computed by dividing net income by the weighted average
+number of shares of common stock outstanding during the year. Diluted net income per common share
+was determined on a weighted average basis using common shares issued and outstanding adjusted for
+the effect of stock options and restricted stock considered common stock equivalents computed using
+the treasury stock method. Diluted net income per share for 2005 also includes the dilutive effect
+of the convertible preferred stock.
+A reconciliation of the basic and diluted net income per share computation is as follows (in
+thousands, except per share amounts):
+2007 
+2006 
+2005 
+(a) Net income available to common shares 
+$ 
+15,194 
+$ 
+40,560 
+$ 
+26,458 
+Preferred dividends assuming conversion of
+preferred stock (if dilutive) 
+— 
+— 
+318 
+(b) Net income available to common shares assum-
+ing conversion of preferred stock (if dilutive) 
+$ 
+15,194 
+$ 
+40,560 
+$ 
+26,776 
+(c) Weighted average shares outstanding 
+20,776 
+20,270 
+18,453 
+Dilutive impact of stock options 
+148 
+238 
+348 
+Dilutive impact of restricted stock 
+40 
+78 
+69 
+Dilutive impact of warrants 
+326 
+777 
+1,375 
+Convertible preferred stock (if dilutive) 
+— 
+— 
+638 
+(d) Weighted average shares outstanding for diluted net income per share 
+21,290 
+21,363 
+20,883 
+Stock options excluded due to the exercise
+price being greater than the stock price 
+75 
+28 
+1 
+Basic net income per share (a ¸ c) 
+$ 
+0.73 
+$ 
+2.00 
+$ 
+1.43 
+Diluted net income per share (b ¸ d) 
+$ 
+0.71 
+$ 
+1.90 
+$ 
+1.28 
+56 
+Table of Contents 
+5. INCOME TAXES 
+Below is an analysis of deferred income taxes as of December 31, 2007 and 2006.
+December 31, 
+2007 
+2006 
+(In thousands) 
+Deferred tax asset: 
+Federal net operating loss carryforwards 
+$ 
+58,397 
+$ 
+58,051 
+State net operating loss carryforwards 
+36,345 
+33,218 
+Statutory depletion carryforward 
+4,184 
+4,651 
+Alternative minimum tax credit carryforward 
+375 
+332 
+Asset retirement obligations 
+11,274 
+12,228 
+Other 
+3,572 
+2,443 
+Valuation allowance 
+(36,345 
+) 
+(33,218 
+) 
+Total deferred tax asset 
+77,802 
+77,705 
+Deferred tax liability: 
+Oil and gas properties 
+(109,530 
+) 
+(101,921 
+) 
+Other 
+(462 
+) 
+(5,838 
+) 
+Total deferred tax liability 
+(109,992 
+) 
+(107,759 
+) 
+Net deferred tax liability 
+$ 
+(32,190 
+) 
+$ 
+(30,054 
+) 
+If not utilized, the Company’s federal net operating loss carryforwards will expire in 2013 through
+2021. The Company’s state net operating loss carryforwards will expire in 2008 through 2021. The
+Company has very limited state taxable income as primarily all of its revenue is generated in
+federal waters not subject to state income taxes. Accordingly, the Company has established a full
+valuation allowance on the tax benefit associated with these state net operating loss carryforwards
+as the Company does not anticipate generating taxable state income in the states in which these
+carryforwards apply.
+Callon adopted FIN 48 effective January 1, 2007. The Company had no significant unrecognized tax
+benefits at the date of adoption or at December 31, 2007. Accordingly, the Company does not have
+any interest or penalties related to uncertain tax positions. However, if interest or penalties
+were to be incurred related to uncertain tax positions, such amounts would be recognized in income
+tax expense. Tax periods for years 2004 through 2007 remain open to examination by the federal and
+state taxing jurisdictions to which the Company is subject.
+57 
+Table of Contents 
+Below is a reconciliation of the reported amount of income tax expense attributable to continuing
+operations for the year to the amount of income tax expense that would result from applying
+domestic federal statutory tax rates to pretax income from continuing operations.
+Years Ended December 31, 
+2007 
+2006 
+2005 
+Income tax expense computed at the statutory
+federal income tax rate 
+35 
+% 
+35 
+% 
+35 
+% 
+Other 
+2 
+% 
+— 
+(1 
+)% 
+Effective income tax rate 
+37 
+% 
+35 
+% 
+34 
+% 
+6. OTHER COMPREHENSIVE INCOME 
+The Company’s other comprehensive income (loss) of $(12.0) million, $9.0 million and $1.6 million
+for the years ended December 31, 2007, 2006 and 2005, respectively, relates to the change in fair
+value of its derivatives. Other comprehensive income (loss) was net of income tax expense
+(benefit) of $(6.5) million, $4.7 million and $835,000 for the years ended December 31, 2007, 2006
+and 2005, respectively.
+7. LONG-TERM DEBT 
+Long-term debt consisted of the following at:
+December 31, 
+2007 
+2006 
+(In thousands) 
+Senior secured credit facility 
+$ 
+— 
+$ 
+35,000 
+9.75% Senior Notes (due 2010) net of discount 
+192,012 
+189,862 
+Senior Revolving Credit Facility (due 2014) 
+200,000 
+— 
+Capital lease 
+— 
+872 
+Total long-term debt 
+392,012 
+225,734 
+Less current portion 
+— 
+213 
+Long-term portion 
+$ 
+392,012 
+$ 
+225,521 
+Senior Secured Credit Facility . On August 30, 2006, the Company closed on a four-year amended and
+restated senior secured credit facility underwritten by Union Bank of California, N.A. (“UBOC”).
+The borrowing base which is reviewed and redetermined semi-annually was $50 million at December 31,
+2007. Borrowings under the credit facility are secured by mortgages covering the Company’s major
+producing fields. As of December 31, 2007 there were no borrowings outstanding under the facility;
+however, Callon had a letter of credit outstanding in the amount of $15 million to secure a
+drilling rig for the development of Entrada. See Note 14. As a result, $35 million was available
+for future borrowings under the credit facility as of December 31, 2007.
+58 
+Table of Contents 
+In April 2007, the UBOC senior secured credit facility was amended to allow for the senior
+revolving credit facility discussed below. See Note 14.
+The credit facility bears interest at 0% to 0.50% above a defined base rate depending on
+utilization of the borrowing base or, at the option of the Company, LIBOR plus 1.375% to 2.0% based
+on utilization of the
+borrowing base. Under the senior secured credit facility, a commitment fee of 0.25% or 0.375% per
+annum, depending on the amount of the unused portion of the borrowing base, is payable quarterly.
+The range of interest rates on the senior secured credit facility during 2007 was 6.54% to 8.75%.
+Senior Revolving Credit Facility (due 2014) . On April 18, 2007, Callon closed the Entrada
+acquisition contemporaneous with a seven-year $200 million senior revolving credit facility
+arranged by Merrill Lynch Capital Corporation, which is secured by a lien on the Entrada
+properties. Borrowings outstanding under the facility bear interest at a rate of LIBOR plus 7%.
+The Company borrowed the full commitment amount under the facility at closing to cover the required
+$150 million payment to BP Exploration and Production Company (“BP”) and expenses and fees related
+to the transaction and the balance was used to pay down the Company’s UBOC senior secured credit
+facility. See Note 14.
+9.75% Senior Notes (due 2010). In December 2003, the Company borrowed $185 million pursuant to a
+senior unsecured credit facility. The loans under the credit facility have a stated interest rate
+of 9.75% and a seven-year maturity. In conjunction with the senior unsecured notes, the Company
+issued detachable warrants to purchase 2.775 million shares of its common stock at an exercise
+price of $10 per share and an expiration date of December 2010. The warrants were valued at $10.6
+million and were treated as a discount on the debt. This senior unsecured debt matures December 8,
+2010 and has an effective interest rate of 11.4%. The Company recorded the issuance of these new
+securities at a fair value of $171 million. Deferred costs of $14 million associated with the
+notes are being amortized over the life of the notes.
+During March 2004, Callon borrowed an additional $15 million under its 9.75% senior unsecured
+credit facility bringing the total outstanding under the facility to $200 million. The net proceeds
+of approximately $14 million were primarily used to retire the remaining $10 million of 12% senior
+loans due March 31, 2005 plus a 1% call premium of $100,000. The Company recorded the issuance of
+these additional new securities at a fair value of $14 million. Deferred costs of $1 million
+associated with the notes are being amortized over the life of the notes. See Note 14.
+In March 2004, the $200 million in aggregate principal amount of loans outstanding under the 9.75%
+senior unsecured credit facility were exchanged for 9.75% Senior Notes due 2010, Series A, (“Series
+A notes”), issued pursuant to a senior indenture between Callon and American Stock Transfer & Trust
+Company dated March 15, 2004. On August 12, 2004, the Company completed an offer to exchange its 
+9.75% Senior Notes due 2010, Series B, that have been registered under the Securities Act of 1933,
+for all outstanding Series A notes.
+As of December 31, 2007, 1.617 million of the 2.775 million detachable warrants issued with the
+9.75% Senior Notes due 2010 were exercised. In addition, 265,210 of the $0.01 warrants associated
+with the 12% senior loans, which were redeemed in 2004, were exercised in June 2006.
+59 
+Table of Contents 
+Certain of the Company’s subsidiaries guarantee the Company’s obligations under the $200 million
+9.75% Senior Notes due 2010. The subsidiary guarantors are 100% owned, all of the guarantees are
+full and unconditional and joint and several, the parent company has no independent assets or
+operations and any subsidiaries of the parent company other than the subsidiary guarantors are
+minor.
+Capital Lease . In December 2001, the Company entered into a 10-year gas processing agreement
+associated with a production facility on Callon’s Mobile Block 952 Field with Hanover Compression
+Limited Partnership, which was being accounted for as a capital lease. In May 2007, the Company
+sold the Mobile Block 952 Field and retired the remainder of the capital lease.
+Restrictive Covenants . The Indenture governing our 9.75% senior notes due 2010, our senior secured
+credit facility and our senior revolving credit facility contain various covenants including
+restrictions on additional indebtedness and payment of cash dividends. In addition, our senior
+secured credit facility contains covenants for maintenance of certain financial ratios. The
+Company was in compliance with these covenants at December 31, 2007.
+8. DERIVATIVES 
+The following table summarizes derivative expense for the periods presented (in thousands):
+Years Ended December 31, 
+2007 
+2006 
+2005 
+Amortization of derivative contract premiums 
+$ 
+— 
+$ 
+150 
+$ 
+1,634 
+Change in fair value and settlements of ineffective
+derivative contracts 
+— 
+— 
+4,394 
+$ 
+— 
+$ 
+150 
+$ 
+6,028 
+The change in fair value and settlements of ineffective derivative contracts in 2005 related to
+contracts that were deemed ineffective as a result of a shortfall in production volumes due to
+downtime resulting from damages caused by Hurricanes Katrina and Rita. Cash settlements on
+effective cash flow hedges for the years ended December 31, 2007 and 2006 resulted in an increase
+in oil and gas sales of $8.1 million and $8.9 million, respectively. For the year ended December
+31, 2005, cash settlements on effective cash flow hedges resulted in a reduction in oil and gas
+sales of $10.3 million.
+60 
+Table of Contents 
+Listed in the table below are the outstanding derivative contracts as of December 31, 2007:
+Collars 
+Average 
+Average 
+Volumes per 
+Quantity 
+Floor 
+Ceiling 
+Product 
+Month 
+Type 
+Price 
+Price 
+Period 
+Oil
+30,000
+Bbls
+$65.00
+$81.50
+01/08-12/08 
+Swaps 
+Volumes per 
+Quantity 
+Average 
+Product 
+Month 
+Type 
+Price 
+Period 
+Oil
+15,000
+Bbls
+$91.00
+01/08-12/08 
+Oil
+5,000
+Bbls
+$94.65
+01/08-3/08 
+In September 2007, the Company entered into a six-month interest rate swap with UBOC. Callon will
+pay UBOC a fixed interest rate of 5.43% on a notional amount of $25,000,000 and receive the
+floating LIBOR rate. The objective of the interest rate swap is to minimize the impact of variable
+interest rates by locking into a fixed rate on a portion of the borrowings of the Merrill Lynch
+Senior Secured Credit Agreement. The fair value of this interest rate swap as of December 31, 2007
+was immaterial.
+9. COMMITMENTS AND CONTINGENCIES 
+From time to time, the Company, as part of the Consolidation and other capital transactions,
+entered into registration rights agreements whereby certain parties to the transactions are
+entitled to require the Company to register common stock of the Company owned by them with the SEC
+for sale to the public in firm commitment public offerings and generally to include shares owned by
+them, at no cost, in registration statements filed by the Company. Costs of the offering will not
+include broker’s discounts and commissions, which will be paid by the respective sellers of the
+common stock.
+The Company is involved in various claims and lawsuits incidental to its business. In the opinion
+of management, the ultimate liability thereunder, if any, will not have a material adverse effect
+on the financial position or results of operations of the Company.
+The Company’s Medusa deepwater property is eligible for royalty suspensions pursuant to the Deep
+Water Royalty Relief Act. In addition, the Company has several shallow water, deep natural gas
+properties and prospects that are eligible for royalty suspensions. However, the federal offshore
+leases covering these properties contain “price threshold” provisions for oil and gas prices.
+Under these “price threshold” provisions, if the average monthly New York Mercantile Exchange
+(NYMEX) sales price for oil or gas during a fiscal year exceeds the price threshold for oil or gas,
+respectively, then royalties on the associated production must be paid to the Minerals Management
+Service (MMS) at the rate stipulated in the lease. The price thresholds are adjusted annually by
+the implicit price deflator for the GDP. The determination of whether or not royalties are due as
+a result of the average NYMEX price exceeding the price threshold is made during the first quarter
+of the succeeding year. Any royalty payments due must be made shortly after this determination is
+made. If a royalty payment is due for all production during a year as a result of
+61 
+Table of Contents 
+exceeding the price threshold, the lessee is required to make monthly royalty payments during the
+succeeding fiscal year for the succeeding year’s production. If at the end of any year the average
+NYMEX price is below the price threshold, the lessee can apply for a refund for any associated royalties
+paid during that year and the lessee will not be required to pay royalties monthly during the
+succeeding year for the succeeding year’s production.
+The Company was required to make monthly royalty payments for 2007 deepwater oil and gas production
+and will be required to make monthly royalty payments for 2008. With regard to the shallow water,
+deep
+natural gas royalty relief, the Company was not required to make royalty payments for 2007 and will
+not be required to make royalty payments for 2008.
+In the year succeeding the year in which any of the Company’s properties became subject to
+royalties as the result of the average NYMEX price exceeding the price threshold, the portion of
+reserves attributable to potential future royalties would not be included in the year-end reserve
+report. However, if the average NYMEX prices were below the price thresholds in subsequent years,
+our reserves would be increased to reflect reserves previously attributed to future royalties. As
+a result, reported oil and gas reserves could materially increase or decrease, depending on the
+relation of price thresholds versus the average NYMEX prices. The reduction in revenues resulting
+from an obligation to pay these royalties and subsequent reduction of proved reserves could have a
+material adverse effect on the Company’s results of operations and financial condition. The
+Company’s reserve report as of December 31, 2007 excluded oil and gas reserves for Medusa that are
+subject to MMS royalties as a result of the average 2007 NYMEX prices for oil and gas exceeding the
+deepwater price thresholds. With regard to the shallow water, deep natural gas properties, there
+was no reduction in reserves for potential future royalties as of December 31, 2007 as a result of
+the average 2007 NYMEX price for gas being below the price threshold.
+The Company’s Entrada Field is governed by leases from the MMS. These leases granted royalty
+suspension without provisions for pricing thresholds for crude oil and natural gas which would
+require the Company to pay royalties to the MMS if the thresholds were exceeded by the current year
+average of NYMEX prices. The MMS has notified Callon that the exclusion of the pricing provisions
+occurred in error in the lease issuance process and was not the MMS’s intention. Congress is
+considering various bills to address this issue, and if a bill were to pass to amend the leases to
+provide thresholds for crude oil and natural gas prices, the reserves for Entrada could be subject
+to such royalties. However, the MMS stated in their correspondence to the Company that they will
+continue to honor the terms of the leases as issued unless notified otherwise. This correspondence
+applies only to Callon’s original 20% working interest in the Entrada Field, the acquired 80%
+working interest is subject to such royalties.
+The Company’s activities are subject to federal, state and local laws and regulations governing
+environmental quality and pollution control. Although no assurances can be made, the Company
+believes that, absent the occurrence of an extraordinary event, compliance with existing federal,
+state and local laws, rules and regulations governing the release of materials into the environment
+or otherwise relating to the protection of the environment will not have a material effect upon the
+capital expenditures, earnings or the competitive position of the Company with respect to its
+existing assets and operations. The Company cannot predict what effect additional regulation or
+legislation, enforcement polices thereunder, and claims for damages to property, employees, other
+persons and the environment resulting from the Company’s operations could have on its activities.
+62 
+Table of Contents 
+10. ASSET RETIREMENT OBLIGATIONS 
+The following table summarizes the activity for the Company’s asset retirement obligations:
+Years Ended December 31, 
+2007 
+2006 
+Asset retirement obligations at beginning of period 
+$ 
+41,179 
+$ 
+38,273 
+Accretion expense 
+3,985 
+4,960 
+Liabilities incurred 
+6,368 
+1,440 
+Liabilities settled 
+(19,519 
+) 
+(16,970 
+) 
+Revisions to estimate 
+4,824 
+13,476 
+Asset retirement obligation at end of period 
+36,837 
+41,179 
+Less: current retirement obligations 
+(9,810 
+) 
+(14,355 
+) 
+Long-term retirement obligations 
+$ 
+27,027 
+$ 
+26,824 
+Assets, primarily short-term U.S. Government securities, of approximately $4.6 million at December
+31, 2007, of which $100,000 was current, were recorded as restricted investments. These assets are
+held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s
+oil and gas properties.
+63 
+Table of Contents 
+11. OIL AND GAS PROPERTIES 
+The following table discloses certain financial data relating to the Company’s oil and gas
+activities, all of which are located in the United States.
+Years Ended December 31, 
+2007 
+2006 
+2005 
+(In thousands) 
+Capitalized costs incurred: 
+Evaluated Properties- 
+Beginning of period balance 
+$ 
+1,096,907 
+$ 
+937,698 
+$ 
+862,101 
+Property acquisition costs 
+154,193 
+4,053 
+6,627 
+Exploration costs 
+35,959 
+73,659 
+46,379 
+Development costs 
+62,845 
+81,497 
+22,591 
+End of period balance 
+$ 
+1,349,904 
+$ 
+1,096,907 
+$ 
+937,698 
+Unevaluated Properties (excluded from
+amortization) - 
+Beginning of period balance 
+$ 
+54,802 
+$ 
+49,065 
+$ 
+39,042 
+Additions 
+21,525 
+19,103 
+18,739 
+Capitalized interest 
+7,152 
+6,477 
+5,655 
+Transfers to evaluated 
+(13,303 
+) 
+(19,843 
+) 
+(14,371 
+) 
+End of period balance 
+$ 
+70,176 
+$ 
+54,802 
+$ 
+49,065 
+Accumulated depreciation, depletion
+and amortization- 
+Beginning of period balance 
+$ 
+604,682 
+$ 
+539,399 
+$ 
+494,453 
+Provision charged to expense 
+72,762 
+65,283 
+44,946 
+Sale of mineral interests 
+60,930 
+— 
+— 
+End of period balance 
+$ 
+738,374 
+$ 
+604,682 
+$ 
+539,399 
+Unevaluated property costs, primarily lease acquisition costs incurred at federal and state lease
+sales, unevaluated drilling costs, capitalized interest and general and administrative costs being
+excluded from the amortizable evaluated property base, consisted of $28.0 million incurred in 2007,
+$16.8 million incurred in 2006, $15.6 million incurred in 2005 and $9.8 million incurred in 2004
+and prior. These costs are directly related to the acquisition and evaluation of unproved
+properties and major development projects. The excluded costs and related reserves are included in
+the amortization base as the properties are evaluated and proved reserves are established or
+impairment is determined. The Company expects that the majority of these costs will be evaluated
+over the next three to five years.
+Depletion per unit-of-production (thousand cubic feet of gas equivalent) amounted to $3.89, $3.14
+and $2.39 for the years ended December 31, 2007, 2006, and 2005, respectively.
+Under the full-cost accounting rules of the SEC, the Company reviews the carrying value of its
+proved oil and gas properties each quarter. Under these rules, capitalized costs of oil and gas
+properties, net of accumulated depreciation, depletion and amortization and deferred income taxes,
+may not exceed the present value of estimated future net cash flows from proved oil and gas
+reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of
+related tax effects (the full-cost ceiling amount). These rules generally require pricing future
+oil and gas production at the unescalated market price for oil and gas at the end of each fiscal
+quarter and require a write-down if the “ceiling” is exceeded. However, if prices recover
+sufficiently subsequent to the balance sheet date before the release of the financial statements
+then
+64 
+Table of Contents 
+use of subsequent pricing is allowed and no write-down would be required if such pricing was used.
+Given the volatility of oil and gas prices, it is reasonably possible that the Company’s estimate
+of discounted
+future net cash flows from proved oil and gas reserves could change in the near term. If oil and
+gas prices decline significantly, even if only for a short period of time, it is possible that
+write-downs of oil and gas properties could occur in the future.
+12. EMPLOYEE BENEFIT PLANS 
+The Company has adopted a series of incentive compensation plans designed to align the interest of
+the executives and employees with those of its stockholders. The following is a brief description
+of each plan:
+Savings and Protection Plan 
+The Savings and Protection Plan (“401-K Plan”) provides employees with the
+option to defer receipt of a portion of their compensation and the Company may, at
+its discretion, match a portion of the employee’s deferral with cash and Company
+Common Stock. The Company may also elect, at its discretion, to contribute a
+non-matching amount in cash and Company Common Stock to employees. The amounts held
+under the 401-K Plan are invested in various funds maintained by a third party in
+accordance with the directions of each employee. An employee is fully vested,
+including Company discretionary contributions, immediately upon participation in the
+401-K Plan. The total amounts contributed by the Company, including the value of
+the common stock contributed, were $680,000, $615,000 and $557,000 in the years
+2007, 2006 and 2005, respectively.
+1996 Stock Incentive Plan 
+On August 23, 1996, the Board of Directors of the Company approved and adopted
+the Callon Petroleum Company 1996 Stock Incentive Plan (the “1996 Plan”). The 1996
+Plan was approved by the shareholders in 1997 and limited to a maximum of 1,200,000
+shares (as amended from the original 900,000 shares) of common stock subject to
+outstanding awards. The 1996 Plan was amended again and approved on May 9, 2000 at
+the Annual Meeting of Shareholders, increasing the number of shares reserved for
+issuance under the 1996 plan to 2,200,000 shares. Unvested options are subject to
+forfeiture upon certain termination of employment events and expire 10 years from
+the date of grant.
+In August 2006, the Board of Directors approved the award of 520,000 shares of
+restricted stock from the 1996 Plan. Of the 520,000 shares, 20,000 shares were
+granted to non-employee members of the Board of Directors and vested immediately.
+The remaining 500,000 shares were issued to employees of the Company with 20% vesting
+immediately and the remaining 80% vesting ratably over the next four years. The
+compensation cost with respect to the 20% that vested immediately was recognized as
+an expense on the grant date and the compensation cost with respect to the remaining
+80% is being amortized to expense over the vesting period.
+65 
+Table of Contents 
+2002 Stock Incentive Plan 
+On February 14, 2002, the Board of Directors of the Company approved and
+adopted the 2002 Stock Incentive Plan (the “2002 Plan”). Pursuant to the 2002 Plan,
+350,000 shares of common stock shall be reserved for issuance upon the exercise of
+options or for grants of stock options, stock appreciation rights or units, bonus
+stock, or performance shares or units. This Plan qualified as a “broadly based” plan
+under the provisions of the New York Stock Exchange’s rules and regulations and
+therefore did not require shareholder approval. Because the 2002 Plan is a broadly
+based plan, the aggregate number of shares underlying awards granted to officers and
+directors cannot exceed 50% of the total number of shares underlying the awards
+granted to all employees during any three-year period.
+In 2006, 17,500 shares were awarded as restricted stock with 20% vesting immediately
+and the remaining 80% vesting ratably over the next four years. The compensation cost
+with respect to the 20% that vested immediately was recognized as an expense on the
+grant date and the compensation cost with respect to the remaining 80% is being
+amortized to expense over the vesting period.
+2006 Stock Incentive Plan 
+On March 9, 2006, the Board of Directors of the Company approved the 2006 Stock
+Incentive Plan (“2006 Plan”). The 2006 Plan was approved by the shareholders at the
+May 4, 2006 annual meeting. Pursuant to the 2006 Plan, 500,000 shares of common
+stock shall be reserved for issuance upon exercise of stock options, restricted
+stock or other stock-based awards. In 2006, 45,000 shares were awarded as
+restricted stock that will vest ratably over the next four years. The compensation
+cost with respect to this grant is being amortized to expense over the vesting
+period.
+13. EQUITY TRANSACTIONS 
+On June 13, 2005, Callon called for redemption all of the Company’s outstanding shares of $2.125
+Convertible Exchange Preferred Stock, Series A. A notice of redemption and letter of transmittal
+was mailed to all holders of record as of the close of business on June 10, 2005. 573,108 shares
+of preferred stock were converted into 1,302,572 shares of the Company’s common stock and 23,563
+shares of the Company’s preferred stock were redeemed for $606,000 on July 14, 2005.
+The Company adopted a stockholder rights plan on March 30, 2000, designed to assure that the
+Company’s stockholders receive fair and equal treatment in the event of any proposed takeover of
+the Company and to guard against partial tender offers, squeeze-outs, open market accumulations,
+and other abusive tactics to gain control without paying all stockholders a fair price. The rights
+plan was not adopted in response to any specific takeover proposal. Under the rights plan, the
+Company declared a dividend of one right (“Right”) on each share of the Company’s Common Stock.
+Each Right will entitle the holder to purchase one one-thousandth of a share of a Series B
+Preferred Stock, par value $0.01 per share, at an exercise price of $90 per one one-thousandth of a
+share.
+The Rights are not currently exercisable and will become exercisable only in the event a person or
+group acquires, or engages in a tender or exchange offer to acquire, beneficial ownership of 15
+percent or more (one existing stockholder was granted an exception for up to 21 percent) of the
+Company’s common stock. After the Rights become exercisable, each Right will also entitle its
+holder to purchase a number of
+66 
+Table of Contents 
+common shares of the Company having a market value of twice the exercise price. The dividend
+distribution was made to stockholders of record at the close of business on April 10, 2000. The
+Rights will expire on March 30, 2010.
+14. ENTRADA ACQUISITION AND DEVELOPMENT 
+On April 18, 2007, the Company completed an acquisition of BP’s 80% working interest in the Entrada
+field for a purchase price of $190 million. The purchase price included $150 million payable at
+closing and an additional $40 million payable after the achievement of certain production
+milestones. The purchased interests included five federal offshore blocks at Garden Banks Blocks
+738, 782, 785, 826 and 827, subject to certain depth limitations. As a result of the acquisition,
+Callon owns a 100% working interest in the Entrada field and is operator. The acquisition added
+150 billion cubic feet of natural gas equivalent (Bcfe) to Callon’s proved undeveloped reserves.
+The acquisition was recorded at fair value based on the initial purchase price of $150 million.
+The Company may record the additional $40 million as additional purchase price in the future when
+the production milestones are achieved, in accordance with the terms of the agreement.
+To finance the initial $150 million payment of the purchase price, Callon closed on a seven-year
+$200 million senior revolving credit facility arranged by Merrill Lynch Capital Corporation
+contemporaneous with the closing of the acquisition. The facility is secured by a lien on the
+Entrada properties. The Company borrowed the full commitment amount under the facility at closing
+to cover the required $150 million payment to BP and expenses and fees related to the transaction
+and the balance was used to pay down our UBOC senior secured credit facility.
+In August 2007, Callon entered into a production handling agreement (“PHA”) with ConocoPhillips and
+Devon Energy Corporation. The PHA provides for production from the Entrada field to be processed
+through the Magnolia production platform, which is owned by ConocoPhillips and Devon.
+Subsequent to December 31, 2007, the Company entered into an agreement with CIECO Energy (US)
+Company (“CIECO”) to sell 50% of the Company’s working
+interest in the Entrada Field for a purchase price of $175
+million with $155 million payable at closing and the additional $20 million payable
+after the achievement of certain production milestones. Additional
+contingent cash payments could be payable based on additional
+cumulative production milestones. Also, CIECO will reimburse Callon
+for 50% of Entrada development expenditures incurred prior to the
+closing date. In addition, CIECO has
+agreed to provide a non-recourse loan of $150 million to Callon for financing of Callon’s 50% share
+of the estimated costs to develop the Entrada field. In connection with this financing, waivers
+and consents are required for the UBOC senior secured credit facility and by a majority of the
+holders of the 9.75% Senior Notes (due 2010).
+67 
+Table of Contents 
+15. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED) 
+The Company’s proved oil and gas reserves at December 31, 2007, 2006 and 2005 have been estimated
+by Huddleston & Co., Inc., the Company’s independent petroleum engineers. The reserves were
+prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve
+estimates are based upon existing economic and operating conditions.
+There are numerous uncertainties inherent in establishing quantities of proved reserves. The
+following reserve data represents estimates only and should not be construed as being exact. In
+addition, the standardized measure of discounted future net cash flows should not be construed as
+the current market value of the Company’s oil and gas properties or the cost that would be incurred
+to obtain equivalent reserves. See Note 9 regarding the provisions for royalty relief and the
+effect on reserves.
+68 
+Table of Contents 
+Estimated Reserves 
+Changes in the estimated net quantities of crude oil and natural gas reserves, all of which are
+located onshore and offshore in the continental United States, are as follows:
+Reserve Quantities 
+Years Ended December 31, 
+2007 
+2006 
+2005 
+Proved developed and undeveloped reserves: 
+Crude Oil (MBbls): 
+Beginning of period 
+13,265 
+18,428 
+19,748 
+Revisions to previous estimates 
+(1,152 
+) 
+(3,733 
+) 
+316 
+(a) 
+Change in ownership 
+144 
+— 
+— 
+Purchase of reserves in place 
+13,658 
+— 
+71 
+Sale of reserves in place 
+(356 
+) 
+— 
+— 
+Extensions and discoveries 
+35 
+204 
+129 
+Production 
+(1,063 
+) 
+(1,634 
+) 
+(1,836 
+) 
+End of period 
+24,531 
+13,265 
+18,428 
+Natural Gas (MMcf): 
+Beginning of period 
+66,037 
+78,021 
+72,619 
+Revisions to previous estimates 
+(3,022 
+) 
+(15,557 
+) 
+(4,946 
+) 
+Change in ownership 
+192 
+— 
+— 
+Purchase of reserves in place 
+68,068 
+— 
+1,308 
+Sale of reserves in place 
+(3,690 
+) 
+— 
+— 
+Extensions and discoveries 
+1,209 
+14,550 
+16,808 
+Production 
+(12,340 
+) 
+(10,977 
+) 
+(7,768 
+) 
+End of period 
+116,454 
+66,037 
+78,021 
+Proved developed reserves: 
+Crude Oil (MBbls): 
+Beginning of period 
+5,159 
+7,323 
+10,292 
+End of period 
+4,723 
+5,159 
+7,323 
+Natural Gas (MMcf): 
+Beginning of period 
+36,750 
+30,982 
+33,982 
+End of period 
+22,340 
+36,750 
+30,982 
+(a) 
+Includes Medusa royalty adjustment 
+69 
+Table of Contents 
+Standardized Measure 
+The following tables present the Company’s standardized measure of discounted future net cash flows
+and
+changes therein relating to proved oil and gas reserves and were computed using reserve valuations
+based on regulations prescribed by the SEC. These regulations provide that the oil and gas price
+structure utilized to project future net cash flows reflect period-end prices (approximately $7.59
+per Mcf for natural gas and $90.92 per Bbl for oil for the 2007 disclosures, $5.78 per Mcf and
+$54.07 per Bbl for 2006 disclosures, and $10.13 per Mcf and $55.44 per Bbl for 2005 disclosures) at
+each date presented with no escalation. Future production and development costs are based on
+current costs without escalation. The resulting net future cash flows have been discounted to
+their present values based on a 10% annual discount factor.
+Standardized Measure 
+Years Ended December 31, 
+2007 
+2006 
+2005 
+(In thousands) 
+Future cash inflows 
+$ 
+3,113,759 
+$ 
+1,101,182 
+$ 
+1,814,208 
+Future costs -
+Production 
+(390,669 
+) 
+(243,740 
+) 
+(238,321 
+) 
+Development and net abandonment 
+(405,186 
+) 
+(81,700 
+) 
+(88,070 
+) 
+Future net inflows before income taxes 
+2,317,904 
+775,742 
+1,487,817 
+Future income taxes 
+(699,967 
+) 
+(119,685 
+) 
+(379,287 
+) 
+Future net cash flows 
+1,617,937 
+656,057 
+1,108,530 
+10% discount factor 
+(483,948 
+) 
+(185,266 
+) 
+(270,978 
+) 
+Standardized measure of discounted
+future net cash flows 
+$ 
+1,133,989 
+$ 
+470,791 
+$ 
+837,552 
+Changes in Standardized Measure 
+Years Ended December 31, 
+2007 
+2006 
+2005 
+(In thousands) 
+Standardized measure – beginning of period 
+$ 
+470,791 
+$ 
+837,552 
+$ 
+515,893 
+Sales and transfers, net of production costs 
+(142,973 
+) 
+(153,387 
+) 
+(116,913 
+) 
+Net change in sales and transfer prices,
+net of production costs 
+411,525 
+(347,193 
+) 
+391,570 
+Net change due to purchases and sales of in
+place reserves 
+795,595 
+— 
+— 
+Extensions, discoveries, and improved
+recovery, net of future production and
+development costs incurred 
+(201,750 
+) 
+122,862 
+127,848 
+Revisions of quantity estimates 
+(66,735 
+) 
+(155,342 
+) 
+(17,241 
+) 
+Accretion of discount 
+53,474 
+108,871 
+61,259 
+Net change in income taxes 
+(393,530 
+) 
+187,209 
+(154,460 
+) 
+Changes in production rates, timing and other 
+207,592 
+(129,781 
+) 
+29,596 
+Aggregate change 
+663,198 
+(366,761 
+) 
+321,659 
+Standardized measure — end of period 
+$ 
+1,133,989 
+$ 
+470,791 
+$ 
+837,552 
+At year-end 2006, a downward revision was made by the Company’s independent petroleum engineers to
+Entrada’s estimated net proved reserves as of December 31, 2006 due to new performance data from
+analogous deepwater reservoirs.
+70 
+Table of Contents 
+16. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) 
+First 
+Second 
+Third 
+Fourth 
+Quarter 
+Quarter 
+Quarter 
+Quarter 
+2007 
+(In thousands, except per share data) 
+Total revenues 
+$ 
+45,484 
+$ 
+43,474 
+$ 
+37,869 
+$ 
+43,941 
+Income from operations 
+13,705 
+12,828 
+13,090 
+16,727 
+Net income 
+5,803 
+2,581 
+2,268 
+4,542 
+Net income per common share-basic 
+$ 
+0.28 
+$ 
+0.12 
+$ 
+0.11 
+$ 
+0.22 
+Net income per common share-diluted 
+0.27 
+0.12 
+0.11 
+0.21 
+First 
+Second 
+Third 
+Fourth 
+Quarter 
+Quarter 
+Quarter 
+Quarter 
+2006 
+(In thousands, except per share data) 
+Total revenues 
+$ 
+45,581 
+$ 
+47,057 
+$ 
+44,878 
+$ 
+44,752 
+Income from operations 
+22,605 
+21,616 
+17,815 
+12,367 
+Net income 
+12,767 
+12,303 
+9,630 
+5,860 
+Net income per common share-basic 
+$ 
+0.66 
+$ 
+0.61 
+$ 
+0.47 
+$ 
+0.28 
+Net income per common share-diluted 
+0.60 
+0.57 
+0.45 
+0.27 
+71 
+Table of Contents 
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+There have been no disagreements with the independent auditors on any matters of accounting
+principles or practices, financial statement disclosure, or auditing scope or procedures.
+ITEM 9.A CONTROLS AND PROCEDURES 
+The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the
+Securities Exchange Act of 1934, or the Exchange Act. This term refers to the controls and
+procedures of a company that are designed to ensure that information required to be disclosed by a
+company in the reports that it files or submits under the Exchange Act is recorded, processed,
+summarized and reported within the time periods specified by the Securities and Exchange
+Commission. Our management, including our Chief Executive Officer and Chief Financial Officer, has
+evaluated the effectiveness of our disclosure controls and procedures as of the end of the period
+covered by this annual report. Based upon that evaluation, our Chief Executive Officer and Chief
+Financial Officer have concluded that our disclosure controls and procedures were effective as of
+the end of the period covered by this annual report. There were no changes to our internal control
+over financial reporting during our last fiscal quarter that have materially affected, or are
+reasonable likely to materially affect, our internal control over financial reporting.
+Management’s Report On Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over
+financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the
+supervision and with the participation of our management, including our principal executive and
+financial officers, we conducted an evaluation of the effectiveness of our internal control over
+financial reporting as of December 31, 2007 based on the frame work in the Internal
+Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
+Commission. Based on our evaluation under the framework in Internal Control-Integrated Framework,
+our management concluded that our internal control over financial reporting was effective as of
+December 31, 2007.
+Ernst & Young LLP, our independent registered public accounting firm, has issued an attestation
+report on the Company’s internal control over financial reporting as of December 31, 2007.
+72 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm
+The Board
+of Directors and Stockholders of 
+Callon Petroleum Company
+We have audited Callon Petroleum Company’s internal control over financial reporting as of December
+31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the
+Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Callon
+Petroleum Company’s management is responsible for maintaining effective internal control over
+financial reporting and for its assessment of the effectiveness of internal control over financial
+reporting included in the accompanying Management’s Report on Internal Control over Financial
+Reporting. Our responsibility is to express an opinion on the Company’s internal control over
+financial reporting based on our audit.
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
+Board (United States). Those standards require that we plan and perform the audit to obtain
+reasonable assurance about whether effective internal control over financial reporting was
+maintained in all material respects. Our audit included obtaining an understanding of internal
+control over financial reporting, assessing the risk that a material weakness exists, testing and
+evaluating the design and operating effectiveness of internal control based on the assessed risk,
+and performing such other procedures as we considered necessary in the circumstances. We believe
+that our audit provides a reasonable basis for our opinion.
+A company’s internal control over financial reporting is a process designed to provide reasonable
+assurance regarding the reliability of financial reporting and the preparation of financial
+statements for external purposes in accordance with generally accepted accounting principles. A
+company’s internal control over financial reporting includes those policies and procedures that (1)
+pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
+transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
+transactions are recorded as necessary to permit preparation of financial statements in accordance
+with generally accepted accounting principles, and that receipts and expenditures of the company
+are being made only in accordance with authorizations of management and directors of the company;
+and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
+acquisition, use, or disposition of the company’s assets that could have a material effect on the
+financial statements.
+Because of its inherent limitations, internal control over financial reporting may not prevent or
+detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
+subject to the risk that controls may become inadequate because of changes in conditions, or that
+the degree of compliance with the policies or procedures may deteriorate.
+In our opinion, Callon Petroleum Company maintained, in all material respects, effective internal
+control over financial reporting as of December 31, 2007, based on the COSO criteria.
+73 
+Table of Contents 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight
+Board (United States), the consolidated balance sheets of Callon Petroleum Company as of December
+31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity and
+cash flows for each of the three years in the period ended December 31, 2007 and our report dated March 13, 2008, expressed an unqualified opinion thereon.
+/s/ Ernst & Young LLP 
+New Orleans, Louisiana 
+March 13, 2008
+74 
+Table of Contents 
+ITEM 9.B OTHER INFORMATION 
+We have disclosed all information required to be disclosed in a current report on Form 8-K during
+the fourth quarter of the year ended December 31, 2007 in previously filed reports on Form 8-K.
+75 
+Table of Contents 
+PART III. 
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. 
+For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders to be held on May 1, 2008 which will be filed with
+the Securities and Exchange Commission and is incorporated herein by reference.
+The Company has adopted a code of ethics that applies to the Company’s chief executive officer,
+chief financial officer and chief accounting officer. The full text of such code of ethics has
+been posted on the Company’s website at www.callon.com, and is available free of charge in print to
+any shareholder who requests it. Request for copies should be addressed to the Secretary at 200
+North Canal Street, Natchez, Mississippi 39120.
+ITEM 11. EXECUTIVE COMPENSATION. 
+For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders to be held on May 1, 2008 which will be filed with
+the Securities and Exchange Commission and is incorporated herein by reference.
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
+STOCKHOLDER MATTERS. 
+For information concerning the security ownership of certain beneficial owners and management, see
+the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of
+Stockholders to be held on May 1, 2008 which will be filed with the Securities and Exchange
+Commission and is incorporated herein by reference.
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders to be held on May 1, 2008 which will be filed with
+the Securities and Exchange Commission and is incorporated herein by reference.
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES. 
+For information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders to be held on May 1, 2008 which will be filed with
+the Securities and Exchange Commission and is incorporated herein by reference.
+76 
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0000928022/2007/0000950134-08-004915/item13.txt b/raw/filings/0000928022/2007/0000950134-08-004915/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..19c711b3fd42c81d650c2377817cd5e251f9e430
--- /dev/null
+++ b/raw/filings/0000928022/2007/0000950134-08-004915/item13.txt
@@ -0,0 +1,4 @@
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company
+relating to the Annual Meeting of Stockholders to be held on May 1, 2008 which will be filed with
+the Securities and Exchange Commission and is incorporated herein by reference.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2007/0000950134-08-004915/item9a.txt b/raw/filings/0000928022/2007/0000950134-08-004915/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2007/0000950134-08-004915/rp_note.txt b/raw/filings/0000928022/2007/0000950134-08-004915/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2007/0000950134-08-004915/rpt_disclosure.txt b/raw/filings/0000928022/2007/0000950134-08-004915/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..f998100e62b483aa804aef934553747e967e0475
--- /dev/null
+++ b/raw/filings/0000928022/2007/0000950134-08-004915/rpt_disclosure.txt
@@ -0,0 +1,11 @@
+Certain Relationships and Related Party Transactions . Our Audit Committee charter provides
+that the Company shall not enter into a related party transaction unless such transaction is
+approved by the Audit Committee after a review of the transaction by the Audit Committee for
+potential conflicts of interest. A transaction will be considered a “related party transaction” if
+the transaction would be required to be disclosed under Item 404 of Regulation S-K. In addition,
+our Code of Business Conduct and Ethics provides that an officer’s or a director’s conflict of
+interest with the Company may only be waived if the Nominating and Governance Committee approves
+the waiver and the full Board of Directors ratifies the waiver. The Committees have the authority
+to hire legal, accounting, financial or other advisors as it may deem necessary or desirable and/or
+to delegate responsibilities to executive officers of the Company in connection with discharging
+their duties. As of December 31, 2007, we are not aware of any related party transactions with our
\ No newline at end of file
diff --git a/raw/filings/0000928022/2012/0000928022-13-000023/filing.txt b/raw/filings/0000928022/2012/0000928022-13-000023/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..6a97ed79d787e4a10014997b45b3b609854a0c98
--- /dev/null
+++ b/raw/filings/0000928022/2012/0000928022-13-000023/filing.txt
@@ -0,0 +1,5510 @@
+10-K
+1
+cpe-20121231x10k.htm
+CALLON PETROLEUM COMPANY FORM 10-K FYE 12-31-2012
+CPE-2012.12.31-10K 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+WASHINGTON, D.C. 20549 
+Form 10-K 
+for the year ended 
+December 31, 2012 
+[X] 
+Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2012, or 
+[ ] 
+Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from____ to____ 
+Commission File Number 001-14039 
+CALLON PETROLEUM COMPANY 
+(Exact name of registrant as specified in its charter) 
+Delaware 
+( State or other jurisdiction of incorporation or organization) 
+64-0844345 
+(I.R.S. Employer Identification No.) 
+200 North Canal Street 
+Natchez, Mississippi 
+(Address of principal executive offices) 
+39120 
+(Zip Code) 
+601-442-1601 
+(Registrant's telephone number, including area code) 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of each class: 
+Name of each exchange on which registered: 
+Common Stock, $.01 par value 
+New York Stock Exchange 
+Securities registered pursuant to section 12 (g) of the Act: None 
+Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. 
+Yes [ ] 
+No [ X ] 
+Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. 
+Yes [ ] 
+No [ X ] 
+Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 
+Yes [ X ] 
+No [ ] 
+Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 
+Yes [ X ] 
+No [ ] 
+Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] 
+Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one): 
+Large accelerated filer [ ] 
+Accelerated filer [ X ] 
+Non-accelerated filer [ ] 
+Smaller reporting company [ ] 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). 
+Yes [ ] 
+No [ X ] 
+The aggregate market value of the voting and non-voting common equity stock held by non-affiliates of the registrant was $162.0 million as of June 30, 2012 . 
+As of March 8, 2013 , 39,870,136 shares of the Registrant’s common stock, par value $.01 per share, were outstanding. 
+Documents Incorporated by Reference 
+Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2012 ) relating to the Annual Meeting of Stockholders to be held on May 16, 2013 , which are incorporated into Part III of this Form 10-K. 
+Table of Contents 
+TABLE OF CONTENTS 
+Page(s) 
+Special Note Regarding Forward-Looking Statements 
+3 
+Definitions 
+4 
+Part I 
+Items 1 and 2. 
+Business and Properties 
+5 
+Acquisitions and Divestitures 
+7 
+Crude Oil and Natural Gas Properties 
+7 
+Reserves and Production 
+10 
+Production Wells and Leasehold Acreage 
+14 
+Other 
+16 
+Regulations 
+17 
+Available Information 
+22 
+Item 1A. 
+Risk Factors 
+23 
+Item 1B. 
+Unresolved Staff Comments 
+31 
+Item 3. 
+Legal Proceedings 
+31 
+Item 4. 
+Mine Safety Disclosures 
+31 
+Part II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+32 
+Performance Graph 
+32 
+Item 6. 
+Selected Financial Data 
+34 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+35 
+Overview and Outlook 
+35 
+Liquidity and Capital Resources 
+37 
+Results of Operations 
+40 
+Significant Accounting Policies and Critical Accounting Estimates 
+46 
+Subsequent Events 
+49 
+Item 7A. 
+Quantitative and Qualitative Disclosures About Market Risk 
+50 
+Item 8. 
+Report of Independent Registered Public Accounting Firm 
+52 
+Financial Statements and Supplementary Data 
+51 
+Consolidated Balance Sheets 
+53 
+Consolidated Statements of Operations 
+54 
+Consolidated Statements of Comprehensive Income 
+55 
+Consolidated Statements of Stockholders' Equity 
+56 
+Consolidated Statements of Cash Flows 
+57 
+Note 1 - Description of Business and Basis of Presentation 
+58 
+Note 2 - Summary of Significant Accounting Policies 
+59 
+Note 3 - Global Settlement with Joint Interest Partner 
+63 
+Note 4 - Earnings per Share 
+63 
+Note 5 - Borrowings 
+64 
+Note 6 - Derivative Instruments and Hedging Activities 
+65 
+Note 7 - Fair Value Measurements 
+68 
+Note 8 - Employee Benefit Plans 
+70 
+Note 9 - Share-Based Compensation 
+71 
+Note 10 - Equity Transactions 
+73 
+Note 11 - Income Taxes 
+73 
+Note 12 - Crude Oil and Natural Gas Properties 
+75 
+Note 13 - Asset Retirement Obligations 
+76 
+Note 14 - Supplemental Crude Oil and Natural Gas Reserve Data (Unaudited) 
+77 
+Note 15 - Commitments and Contingencies 
+80 
+Note 16 - Summarized Quarterly Financial Information (Unaudited) 
+80 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+81 
+Item 9A. 
+Controls and Procedures 
+81 
+Item 9B. 
+Other Information 
+82 
+Report of Independent Registered Public Accounting Firm 
+83 
+Part III 
+Item 10. 
+Directors and Executive Officers and Corporate Governance 
+84 
+Item 11. 
+Executive Compensation 
+84 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+84 
+Item 13. 
+Certain Relationships and Related Transactions and Director Independence 
+84 
+Item 14. 
+Principal Accountant Fees and Services 
+84 
+Part IV 
+Item 15. 
+Exhibits 
+85 
+Signatures 
+88 
+2 
+Special Note Regarding Forward Looking Statements 
+All statements, other than historical fact or present financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve quantities, present value and growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law. 
+Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Form 10-K identified by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions. 
+You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to: 
+• 
+the timing and extent of changes in market conditions and prices for commodities (including regional basis differentials), 
+• 
+our ability to transport our production to the most favorable markets or at all, 
+• 
+the timing and extent of our success in discovering, developing, producing and estimating reserves, 
+• 
+our ability to respond to low natural gas prices, 
+• 
+our ability to fund our planned capital investments, 
+• 
+the impact of government regulation, including any increase in severance or similar taxes, legislation relating to hydraulic fracturing, the climate and over-the-counter derivatives, 
+• 
+the costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment and services, 
+• 
+our future property acquisition or divestiture activities, 
+• 
+the effects of weather, 
+• 
+increased competition, 
+• 
+the financial impact of accounting regulations and critical accounting policies, 
+• 
+the comparative cost of alternative fuels, 
+• 
+conditions in capital markets, changes in interest rates and the ability of our lenders to provide us with funds as agreed, 
+• 
+credit risk relating to the risk of loss as a result of non-performance by our counterparties, and 
+• 
+any other factors listed in the reports we have filed and may file with the Securities and Exchange Commission (“SEC”). 
+We caution you that the forward-looking statements contained in this Form 10-K are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A of this Annual Report on Form 10-K for the year ended December 31, 2012 and all quarterly reports on Form 10-Q filed subsequently thereto (“Form 10-Qs”). 
+Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. 
+All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. 
+3 
+Table of Contents 
+DEFINITIONS 
+All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this report. As used in this document: 
+• 
+3-D : three-dimensional. 
+• 
+ARO : Asset Retirement Obligation. 
+• 
+Bbl or Bbls : barrel or barrels of oil or natural gas liquids. 
+• 
+Bcf : billion cubic feet. 
+• 
+Boe : barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas. The ratio of one barrel of oil or NGL to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas. 
+• 
+Boe/d : Boe per day. 
+• 
+BLM: Bureau of Land Management. 
+• 
+BOEM : Bureau of Ocean Energy Management, Regulation and Enforcement; formerly the Minerals Management Service ("MMS"). 
+• 
+Btu : a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit. 
+• 
+BSEE: Bureau of Safety and Environmental Enforcement. 
+• 
+DOI: Department of Interior. 
+• 
+EPA: Environmental Protection Agency. 
+• 
+GHG: greenhouse gases. 
+• 
+LIBOR : London Interbank Offered Rate. 
+• 
+Mbbls : thousand barrels of oil. 
+• 
+Mboe : thousand boe. 
+• 
+Mboe/d : Mboe per day. 
+• 
+Mcf : thousand cubic feet of natural gas. 
+• 
+Mcfe : thousand cubic feet of natural gas equivalents. 
+• 
+Mcf/d : Mcf per day. 
+• 
+MMbbls : million barrels of oil. 
+• 
+MMboe : million boe. 
+• 
+MMBtu : million Btu. 
+• 
+MMcf : million cubic feet of natural gas. 
+• 
+MMcf/d : MMcf per day. 
+• 
+MMS: Minerals Management Service. 
+• 
+NGL or NGLs : natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams. 
+• 
+NYMEX : New York Mercantile Exchange. 
+• 
+OCS: outer continental shelf. 
+• 
+Oil : includes crude oil and condensate. 
+• 
+ONRR: Office of Natural Resources Revenue. 
+• 
+PDPs : proved developed producing reserves. 
+• 
+PDNPs : proved developed non-producing reserves. 
+• 
+PUDs : proved undeveloped reserves. 
+• 
+Reserve life: a measurement of the time it will take to produce our proved reserves calculated by dividing our estimate net equivalent reserves at December 31, 2012 by our total production during 2012 on an equivalent basis. 
+• 
+SEC : United States Securities and Exchange Commission. 
+• 
+US GAAP: Generally Accepted Accounting Principles in the United States 
+With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross. 
+4 
+Table of Contents 
+PART I. 
+Items 1 and 2 - Business and Properties 
+Overview and Business Strategy 
+Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company partially owned by a member of current management. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+In 2009, the Company began to shift its operational focus from exploration, development and production in the Gulf of Mexico to the acquisition and development of onshore properties. Currently, our onshore properties located in the Permian Basin in Texas are the foundation of our onshore strategy. As of December 31, 2012 , we had estimated net proved reserves of 10.8 MMbbls and 19.8 Bcf, or 14.1 MMboe. Of these reserves and on an MMboe basis, approximately 68% were located onshore in the Permian Basin, compared with approximately 61% located onshore at December 31, 2011 . Additionally, 77% of our proved reserve volumes were crude oil at year-end 2012 compared to 63% at year-end 2011 . 
+Our Business Strategy 
+Our goal is to increase stockholder value by: 
+• 
+Continuing to build our onshore production base through: 
+◦ 
+conversion of our existing Permian acreage position to production 
+◦ 
+leveraging our technical and operational teams across a larger production base 
+◦ 
+pursuing opportunistic producing property and leasehold acquisitions 
+• 
+Focusing on capital efficiency through: 
+◦ 
+exploiting Permian resources through repeatable program drilling 
+◦ 
+continuing to invest in supporting infrastructure 
+◦ 
+high-grading of capital allocation across our expanded drilling portfolio continuing to refine our vertical and horizontal completion techniques and target zones 
+• 
+Delivering on asset growth potential through: 
+◦ 
+focusing on an established production base from vertical Wolfberry wells 
+◦ 
+the drilling inventory of horizontal locations identified in 2012 from our evaluation efforts in the southern Midland basin from horizontal locations developed in 2012 
+◦ 
+exploration activities on our acreage in the northern Midland basin 
+5 
+Table of Contents 
+Our Strengths 
+We believe that we are well positioned to achieve our business objectives and to execute our strategy due to the following factors: 
+• 
+We have assembled a Permian leasehold position of over 32,900 net acres that are prospective for the exploration, development and exploitation of multiple oil-bearing intervals through both vertical and horizontal drilling. 
+• 
+Our initial horizontal drilling efforts commenced in 2012 have resulted in a large inventory of drillable locations in the southern Midland basin for future development of two zones of the Wolfcamp shale, complementing our existing vertical drilling program. We continue to evaluate other intervals prospective for horizontal development that may add to this inventory depending on evaluation results by us and other industry players. 
+• 
+We continue to replace high decline-rate, natural gas production from the Gulf of Mexico shelf area with longer reserve life, liquids-rich production from our Permian drilling programs. As a result, we have increased our reserve life 185% to 8.9 years at year-end 2012 from 4.8 years at year-end 2008. 
+• 
+Our offshore properties generate substantial cash flow, which we can redeploy in the acquisition, exploration and development of onshore properties. Since initiating our onshore transition strategy in 2009, we have invested nearly $263 million of offshore cash flow into our onshore initiatives. 
+• 
+Effective December 28, 2012, we sold our interest in the Habanero field for net cash consideration of $39.4 million , accelerating our cash flows from this offshore property and monetizing the value of additional undeveloped reserve potential. These proceeds allowed us to substantially reduce the outstanding balance on our Senior Secured Revolving Credit Facility (the "Credit Facility"), strengthening our liquidity in 2013 to support our Permian-focused capital development program. 
+• 
+On December 31, 2012 , our total liquidity position was approximately $56.1 million , including $1.1 million of available cash and $55 million of unused borrowing base available under our Credit Facility. The $65 million borrowing base at December 31, 2012 increased by $20 million or 44% over the base at December 31, 2011 . 
+• 
+We have assembled a management team experienced in oil and natural gas acquisitions, exploration, development and production in the areas in which we focus our operations, with an average of 28 years of experience in their relevant fields of expertise. Our technical and operational teams continue to benefit from the knowledge gained from our increased level of activity in the Permian basin and from the addition of new employees with significant industry experience. 
+Exploration and Development Activities 
+Our 2012 capital expenditures approximated $147 million , and represented a 39% increase over 2011 actual capital expenditures. Of the $147 million , approximately 88% was allocated to onshore drilling, development and leasehold acquisition activity in the Permian basin. During 2012 , capital expenditures on an accrual basis for exploration and development costs related to oil and natural gas properties included the following expenditures (in millions): 
+Southern Midland basin 
+$ 
+70.3 
+Northern Midland basin 
+21.4 
+Leasehold acquisitions and seismic 
+37.2 
+Plugging and abandonment costs in the Gulf of Mexico 
+2.3 
+Capitalized interest 
+2.0 
+Capitalized general and administrative costs allocated directly to exploration and development projects 
+13.3 
+Total capital expenditures 
+$ 
+146.5 
+With our continued operational focus onshore, primarily in the Permian basin, we expect that over 92% of our 2013 capital expenditures will be focused on the acquisition, exploration, development and operation of onshore properties, with only 8% of capital expenditures directed towards our offshore properties, excluding the capital required for the subsea development project discussed below. In addition to the 2013 capital program, which is outlined within Management's Discussion and Analysis (Part II, Item 7), we have received various long-lead time requests for capital expenditures related to the proposed subsea development of the Medusa field, and we expect to receive additional requests throughout 2013. The operator plans to begin drilling these 
+6 
+Table of Contents 
+wells will begin in the first quarter of 2014. For additional information, please refer to our Offshore - Deepwater discussion, which is also located within Management's Discussion and Analysis. 
+Recent Developments 
+Acquisitions 
+During the first quarter of 2012, the Company acquired approximately 16,233 gross ( 14,653 net) acres in Borden county, Texas, which is located in the northern Midland basin. The northern Midland basin has had limited drilling activity compared with the southern Midland basin (where our current production is located), increasing the risk of success for these drilling activities. The purchase price of $14.5 million was funded from existing cash balances. During the third quarter of 2012, we acquired an additional 8,095 gross acres ( 6,964 net) in this area for a total consideration of $4.8 million . 
+During the second quarter of 2012, the Company signed a purchase and sale agreement to acquire 2,319 gross ( 1,762 net) acres in southern Reagan county, Texas for a total purchase price of $12.0 million , which was financed with a draw on the Company's Credit Facility. The transaction had an effective date of May 1, 2012 and closed on July 5, 2012. 
+Divestitures 
+On December 28, 2012, we closed the sale of our 11.25% working interest in the Habanero field (Garden Banks Block 341) to Shell Offshore Inc., a subsidiary of Royal Dutch Shell Plc, for an estimated net cash consideration of $39.4 million after customary purchase price adjustments. We used the proceeds from the sale to reduce outstanding borrowings on our Credit Facility, providing additional liquidity to fund our 2013 capital program. The borrowing base under our Credit Facility was revised to $65 million following the Habanero sale, and was redetermined as scheduled in the first quarter of 2013 based upon the evaluation of year-end proved reserves. 
+7 
+Table of Contents 
+Crude Oil and Natural Gas Properties 
+As of December 31, 2012 , our estimated net proved reserves totaled 14.1 MMBoe and included 10.8 MMBbls and 19.8 Bcf, with a pre-tax present value, discounted at 10%, of $250.1 million . Pre-tax present value is a non-US GAAP financial measure, which we reconcile to the US GAAP standardized measure of $231.1 million in note (d) to the table below. Oil constitutes approximately 77% of our total estimated equivalent net proved reserves and approximately 48% of our total estimated equivalent proved developed reserves. 
+The following table sets forth certain information about our estimated net proved reserves prepared by our independent petroleum reserve engineers by major field and for all other properties combined at December 31, 2012 : 
+Pre-tax 
+Discounted 
+Estimated Net Proved Reserves 
+Present 
+Operator 
+Oil 
+(MBbls) 
+Natural Gas 
+(MMcf) 
+Total 
+(MBoe) 
+Value 
+($000) 
+(a) 
+(b)(c)(d) 
+Onshore: 
+Permian basin 
+Callon 
+7,209 
+13,242 
+9,416 
+$ 
+78,950 
+Haynesville shale 
+Callon 
+— 
+1,231 
+205 
+$ 
+666 
+Total Onshore 
+7,209 
+14,473 
+9,621 
+$ 
+79,616 
+Gulf of Mexico Deepwater: 
+Mississippi Canyon 538/582 
+“Medusa” 
+Murphy 
+3,551 
+2,083 
+3,898 
+$ 
+179,967 
+Total Gulf of Mexico Deepwater 
+3,551 
+2,083 
+3,898 
+$ 
+179,967 
+Gulf of Mexico Shelf and Other: 
+West Cameron Block 295 
+Apache 
+5 
+954 
+164 
+$ 
+1,081 
+East Cameron Block 2 
+Apache 
+5 
+487 
+86 
+633 
+East Cameron Block 257 
+SandRidge Energy 
+— 
+1,182 
+197 
+(718 
+) 
+Other (c) 
+Various 
+10 
+574 
+106 
+(10,482 
+) 
+Total Gulf of Mexico Shelf and Other 
+20 
+3,197 
+553 
+$ 
+(9,486 
+) 
+Total Net Proved Reserves 
+10,780 
+19,753 
+14,072 
+$ 
+250,097 
+(a) 
+We convert Mcf to Boe using a conversion ratio of six Mcf to one Bbl. This ratio, which is typical in the industry and represents the approximate energy equivalent of a Mcf to a Bbl, does not reflect to market price equivalence of an Mcf of natural gas compared with a Bbl of oil or NGLs. On a market price equivalence basis, a barrel of oil or NGLs has a substantially higher price than six Mcf of natural gas. 
+(b) 
+Represents the present value of future net cash flows before deduction of federal income taxes, discounted at 10%, attributable to estimated net proved reserves as of December 31, 2012 , as set forth in the Company’s reserve reports prepared by its independent petroleum reserve engineers, Huddleston & Co., Inc. 
+(c) 
+Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2012 , in accordance with accounting for asset retirement obligations rules. The negative Pre-Tax Discounted Present Value of the “Other” reflects plugging and abandonment obligations exceeding the future net cash flows, with most of such obligations estimated to occur within the next five years. 
+(d) 
+The Company uses the financial measure “Pre Tax Discounted Present Value” which is a non-US GAAP financial measure. The Company believes that Pre Tax Discounted Present Value, while not a financial measure in accordance with US GAAP, is an important financial measure used by investors and independent oil and gas producers for evaluating the relative value of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially. The total standardized measure calculated in accordance with the guidance issued by the FASB for disclosures about oil and gas producing activities for our proved reserves as of December 31, 2012 was $231.1 million inclusive of the $18.9 million discounted estimated future income taxes relating to such future net revenues. The projected per Mcf natural gas price of $4.81 used in the 2012 reserve estimates has been adjusted to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected per barrel oil price of $94.68 used in the 2012 reserve estimates has been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. 
+8 
+Table of Contents 
+Onshore Properties 
+Onshore proved reserves accounted for approximately 68% of year-end 2012 proved reserves on a Boe basis as compared to 61% of 2011 reserves on a Boe basis, consistent with our strategy of using our offshore cash flow to explore and develop our onshore properties and following the sale of our offshore interest in the Habanero field. 
+Permian Basin 
+As of December 31, 2012 , we owned approximately 32,962 net acres in the Permian basin, where we are exclusively focused on the Midland sub-basin. Our reserves in the Permian basin represent approximately 67% of our total proved reserves at year-end 2012 as compared to 48% at year-end 2011. Average net production from the Company's Permian basin properties increased 67% to 1,614 Boe/d in 2012 from 967 Boe/d in 2011 . 
+We describe our activities in the Permian basin based on two geographic areas, the southern and northern Midland basin, given their relative stages of development. 
+The southern portion of our position (located in Texas counties of Crockett, Upton, Midland, Ector, Reagan and Glasscock) represents the vast majority of our current Permian production. We have been pursuing a vertical development program in this area since our entry into the Permian in 2009, drilling 71 gross ( 63 net) vertical wells over that period. In 2012, we commenced the horizontal drilling of our properties in Upton and Reagan counties, drilling three net wells targeting the Wolfcamp B shale. 
+Our northern Midland basin position was established in 2012 with the acquisition of 24,328 gross ( 21,617 net) acres in Borden and Lynn counties. We began our exploration program in Borden county during the second half of 2012 , drilling one gross ( 0.8 net) vertical and two gross ( 1.8 net) horizontal wells, targeting the Cline and Mississippi lime. 
+The following table summarizes our wells drilled and completed by area during 2012 : 
+Property 
+Drilling 
+Completion 
+Gross 
+Net 
+Gross 
+Net 
+Southern Midland basin vertical wells 
+15 
+10.7 
+22 
+16.0 
+Southern Midland basin horizontal wells 
+3 
+2.8 
+2 
+2.0 
+Total 
+18 
+13.5 
+24 
+18.0 
+Property 
+Drilling 
+Completion 
+Gross 
+Net 
+Gross 
+Net 
+Northern Midland basin vertical wells 
+1 
+0.8 
+— 
+— 
+Northern Midland basin horizontal wells 
+2 
+1.8 
+1 
+1.0 
+Total 
+3 
+2.6 
+1 
+1.0 
+Other 
+We own a 69% working interest in a 429 net acre unit of the Haynesville shale natural gas unit located in southern Bossier parish, Louisiana. As of December 31, 2012 , our Haynesville shale proved reserves were reduced by 90% compared to year-end 2011 due to low natural gas prices. During 2012 , our one producing well produced 3% of our total production on an equivalent basis. Also during 2012 , this well was shut-in for a combined 112 days during the fourth quarter of 2011 and the first quarter of 2012 due to well interference from an offsetting well. Production was restored in mid-March 2012 following a successful remediation operation and, as of December 31, 2012 , our Haynesville well was producing approximately 751 Mcf of natural gas per day. We currently have no drilling obligations related to this lease position and will wait for natural gas prices to return to a level that would justify capital allocation within our portfolio before recommencing our development of the field. 
+9 
+Table of Contents 
+Gulf of Mexico Deepwater 
+Medusa, Mississippi Canyon Blocks 538/582 
+The Medusa field, in which we own a 15% working interest, is located in 2,235 feet of water approximately 50 miles offshore Louisiana, and currently produces from eight existing wellbores. Murphy Exploration & Production Company (“Murphy”), the operator, owns a 60% working interest and ENI Deepwater, LLC, owns the remaining 25% working interest. Since the field entered production in 2003, cumulative gross volumes have approximated 58 MMBoe. 
+During 2012 , the Medusa field produced 464 MBoe net to Callon from eight wells which accounted for 29% of our total production. Six of the field's wells continue to produce from their initial completions as of December 31, 2012 . We project that 1.1 MMBoe of net PDNPs can be accessed by recompletions in the existing wells. These up-hole recompletions in existing wellbores are expected to occur as existing completions deplete to a level that is uneconomic to justify continued production. We anticipate the development of our current net 1.3 MMBoe of PUD reserves in conjunction with a subsea development program to be commenced during 2014. 
+Gulf of Mexico Shelf 
+Approximately 4% of our year-end 2012 proved reserves were attributable to the shelf area of the Gulf of Mexico and other properties. We own interests in 14 producing wells in eight oil and natural gas fields in the shelf area of the Gulf of Mexico area. These wells produced 340 MBoe net to our interest in 2012 , which accounted for 22% of our total production. 
+For additional information regarding the Company's properties, including its 2013 capital expenditures program and future development plans, please refer to the Properties discussion within Management's Discussion and Analysis, which is located in Part II, Item 7 of this filing. 
+10 
+Table of Contents 
+Proved Reserves 
+Estimates of volumes of proved reserves, net to our interest, at year end are presented in MBbls for oil and in MMcf for natural gas, including NGLs, at a pressure base of 15.025 pounds per square inch. Total volumes are presented in MBoe. For the MBoe computation, 6,000 cubic feet of gas are the equivalent of one barrel of oil. 
+The following table sets forth certain information about our estimated net proved reserves. All of our proved reserves are located in the continental United States and in federal and state waters in the Gulf of Mexico. 
+Years Ended December 31, 
+2012 
+2011 
+2010 
+Proved developed: 
+Oil (MBbls) 
+4,955 
+5,069 
+4,503 
+Natural gas (MMcf) 
+10,680 
+11,605 
+12,715 
+MBoe 
+6,735 
+7,003 
+6,622 
+Proved undeveloped: 
+Oil (MBbls) 
+5,825 
+5,006 
+3,645 
+Natural gas (MMcf) 
+9,073 
+23,513 
+20,241 
+MBoe 
+7,337 
+8,925 
+7,019 
+Total proved: 
+Oil (MBbls) 
+10,780 
+10,075 
+8,149 
+Natural gas (MMcf) 
+19,753 
+35,118 
+32,957 
+MBoe 
+14,072 
+15,928 
+13,641 
+Estimated pre-tax future net cash flows (a) 
+$ 
+592,424 
+$ 
+568,798 
+$ 
+379,448 
+Pre-tax discounted present value (a) (b) 
+$ 
+250,097 
+$ 
+309,890 
+$ 
+205,532 
+Standardized measure of discounted future net cash flows(a) (b) 
+$ 
+231,148 
+$ 
+270,357 
+$ 
+198,916 
+(a) 
+Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2012 , in accordance with accounting for asset retirement obligations rules. 
+(b) 
+The Company uses the financial measure “Pre-tax discounted present value” which is a non-US GAAP financial measure. The Company believes that Pre-tax discounted present value, while not a financial measure in accordance with US GAAP, is an important financial measure used by investors and independent oil and gas producers for evaluating the relative value of crude oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially. The total standardized measure calculated in accordance with the guidance issued by the FASB for disclosures about oil and gas producing activities for our proved reserves as of December 31, 2012 was $231.1 million inclusive of the $18.9 million discounted estimated future income taxes relating to such future net revenues. The natural gas Mcf prices of $4.81 used in the 2012 reserve estimates have been adjusted to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected crude oil prices of $94.68 used in the 2012 reserve estimates have been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. 
+See Note 14 of our Consolidated Financial Statements for the additional information regarding the Company’s reserves including its estimates of proved reserves, PDPs, PUDs and the Company’s estimates of future net cash flows and discounted future net cash flows from proved reserves. 
+Estimated net proved reserves at December 31, 2012 , represented a 12% decrease over 2011 year-end estimated net proved reserves primarily due to the sale of the Company's interest in the Habanero field and the downward revision of our Haynesville Shale undeveloped reserves at year-end 2012 , which were reduced due to low natural gas pricing assumptions. These decreases were partially offset by the Company's development of a portion of its Permian basin, on which it added 7 PDP and 19 PUD wells during 2012 . 
+11 
+Table of Contents 
+Proved Undeveloped Reserves ("PUDs") 
+Annually, the Company reviews its PUDs to ensure appropriate plans exist for development. Except as noted below, reserves are recognized as PUDs only if the Company has plans to convert the PUDs into PDPs within five years of the date they are first recorded as PUDs. The basis for our development plans include the allocation of capital to projects included within our 2013 capital budget and, in subsequent years, the allocation of capital within our long-range business plan. Generally, our 2013 capital budget and our long-range capital plans are governed by our expectations of internally generated cash flow and Credit Facility borrowing availability. Reserve calculations at any end-of-year period are representative of our development plans at that time. Changes in commodity pricing, oilfield service costs and availability, and other economic factors may lead to changes in development plans. 
+The following table summarizes the Company’s recorded PUDs: 
+PUDs (MBoe) at December 31, 
+2012 
+2011 
+2010 
+Permian basin 
+6,040 
+4,861 
+2,928 
+Haynesville shale 
+— 
+1,730 
+1,757 
+Total Onshore PUDs 
+6,040 
+6,591 
+4,685 
+Medusa 
+1,297 
+1,186 
+1,186 
+Habanero (a) 
+— 
+1,148 
+1,148 
+Total Deepwater PUDs 
+1,297 
+2,334 
+2,334 
+Total PUDs 
+7,337 
+8,925 
+7,019 
+(a) 
+Effective December 28, 2012, we sold our interest in the Habanero field. See Note 12 for additional information. 
+The Company's PUDs decreased 18% to 7,337 MBoe from 8,925 MBoe at December 31, 2012 and 2011 , respectively. Additions during the year added 2,344 MBoe to the Company's PUDs, offset by (1) 557 MBoe primarily comprised of transfers to PDPs as a result of our development program, (2) 1,148 MBoe related to the sale of Habanero, and (3) 2,227 MBoe related to reductions in our PUD reserves, primarily related to the Haynesville Shale, by amounts no longer deemed to be economic PUDs at year-end. Of our year-end 2011 PUD reserves, 6% were converted to proved developed producing reserves by year end 2012 , at a total cost of approximately $19 million, net. 
+Our 1,297 MBoe of deepwater PUDs have been classified as PUDs for more than five years, though we expect to develop these PUDs within the next two years. Our decision to classify these reserves as PUDs was primarily based on (1) our ongoing development planning in the area, (2) our historical record of completing development of comparable long-term projects, (3) the amount of time which we have maintained the leases or booked reserves without significant development activities and (4) the extent to which we have followed previously adopted development plans. Our discussions with the field's operator have resulted in the modification of certain development plans for Medusa to drill or sidetrack PUDs within a shorter period of time than originally estimated. The Company expects to drill a new well in 2014 within the Medusa field to access the PUD reserves of 1,297 MBoe. During 2012 , the Company did not convert any offshore PUDs to PDPs. 
+The Company's plans to develop its onshore, Permian basin PUDs as part of a multi-year drilling program, which is expected to be completed on existing acreage within five years of the initial recording of any PUD. 
+Controls Over Reserve Estimates 
+Compliance as it relates to reporting the Company’s reserves is the responsibility of our Senior Vice President of Operations, who has over 30 years of industry experience including 25 years as a manager and is our principal engineer. In addition to his years of experience, our principal engineer holds a degree in petroleum engineering and is experienced in asset evaluation and management. 
+Callon’s controls over reserve estimates included retaining Huddleston & Co., Inc. ("Huddleston"), a Texas registered engineering firm, as our independent petroleum and geological firm. The Company provided to Huddleston information about our oil and gas properties, including production profiles, prices and costs, and Huddleston prepared its own estimates of the reserves attributable to the Company’s properties. All of the information regarding reserves in this annual report is derived from Huddleston’s report. Huddleston's reserve report letter is included as an Exhibit to this annual report. The principal engineer at Huddleston who is 
+12 
+Table of Contents 
+responsible for preparing the Company’s reserve estimates has over 30 years of experience in the oil and gas industry and is a Texas Licensed Professional Engineer. Further professional qualifications include a degree in petroleum engineering. 
+To further enhance the control environment over the reserve estimation process, our Board of Directors includes a Strategic Planning Committee whose purpose, as stated in the Committee's charter, includes assisting management and the Board with its oversight of the integrity of the determination of the Company's oil, natural gas and natural gas liquids reserves and work of the Huddleston. The Committee's charter also specifies that the Committee shall perform, in consultation with the Company's management and senior reserves and reservoir engineering personnel, the following responsibilities: 
+• 
+Oversee the appointment, qualification, independence, compensation and retention of the independent petroleum and geological firm (the "Firm") engaged by the Company (including resolution of material disagreements between management and the Firm regarding reserve determination) for the purpose of preparing or issuing an annual reserve report. The Committee shall review any proposed changes in the appointment of the Firm, determine the reasons for such proposal, and whether there have been any disputes between the Firm and management. 
+• 
+Review the Company’s significant reserves engineering principles and policies and any material changes thereto, and any proposed changes in reserves engineering standards and principles which have, or may have, a material impact on the Company’s reserves disclosure. 
+• 
+Review with management and the Firm the proved reserves of the Company, and, if appropriate, the probable reserves, possible reserves and the total reserves of the Company, including: (i) reviewing significant changes from prior period reports; (ii) reviewing key assumptions used or relied upon by the Firm; (iii) evaluating the quality of the reserve estimates prepared by both the Firm and the Company relative to the Company’s peers in the industry; and (iv) reviewing any material reserves adjustments and significant differences between the Company’s and Firm’s estimates. 
+• 
+If the Committee deems it necessary, it shall meet in executive session with management and the Firm to discuss the oil and gas reserve determination process and related public disclosures, and any other matters of concern in respect of the evaluation of the reserves. 
+During our last fiscal year, we filed no reports with other federal agencies which contain an estimate of total proved net oil and natural gas reserves. 
+13 
+Table of Contents 
+Production Volumes, Average Sales Prices and Average Operating Costs 
+The following table sets forth certain information regarding the production volumes and average sales prices received for, and average production costs associated with, the Company’s sale of crude oil and natural gas for the periods indicated. 
+Years Ended December 31, 
+2012 
+2011 
+2010 
+(in thousands, except per unit data) 
+Production 
+Natural gas and NGLs (Mcf) 
+3,588 
+5,081 
+4,892 
+Crude oil (MBbl) 
+977 
+996 
+859 
+Total (MBoe) 
+1,575 
+1,843 
+1,674 
+Revenues 
+Natural gas and NGL sales 
+$ 
+14,149 
+$ 
+26,682 
+24,639 
+Crude oil sales 
+96,584 
+100,962 
+65,243 
+Total revenues 
+$ 
+110,733 
+$ 
+127,644 
+$ 
+89,882 
+Lease Operating Expenses 
+Production costs 
+$ 
+22,981 
+$ 
+17,693 
+$ 
+15,770 
+Severance/production taxes 
+2,430 
+1,826 
+816 
+Gathering 
+349 
+592 
+802 
+Ad Valorem 
+794 
+236 
+324 
+Total lease operating expenses 
+$ 
+26,554 
+$ 
+20,347 
+$ 
+17,712 
+Realized prices 
+Natural gas ($/Mcf, including realized gains (losses) on derivatives) (a) 
+$ 
+3.94 
+$ 
+5.25 
+$ 
+5.04 
+Natural gas ($/Mcf, excluding realized gains (losses) on derivatives) (a) 
+3.94 
+5.25 
+4.91 
+Crude oil ($/Bbl, including realized gains (losses) on derivatives) (b) 
+98.86 
+101.34 
+75.97 
+Crude oil ($/Bbl, excluding realized gains (losses) on derivatives) (b) 
+97.41 
+101.72 
+75.97 
+Operating costs per Boe - Total Consolidated 
+Production costs 
+$ 
+14.59 
+$ 
+9.60 
+$ 
+9.61 
+Severance/production taxes 
+1.54 
+0.99 
+0.49 
+Gathering 
+0.22 
+0.32 
+0.48 
+Ad Valorem 
+0.50 
+0.13 
+0.19 
+Total operating costs per Boe 
+$ 
+16.85 
+$ 
+11.04 
+$ 
+10.77 
+(a) 
+Natural gas prices exceeded the related NYMEX prices, which are quoted on an MMBtu basis, primarily due to the value of the NGLs in our liquids-rich natural gas stream, primarily from our Permian basin and deepwater production. 
+(b) 
+Crude oil prices for production from our two deepwater fields reflect a premium over NYMEX pricing based on Mars WTI differential for Medusa production and Argus Bonita WTI differential for Habanero production, prior to the sale of Habanero during December 2012. 
+14 
+Table of Contents 
+Present Activities and Productive Wells 
+The following table sets forth the wells drilled and completed during the periods indicated. All such wells were drilled in the continental United States and in federal and state waters in the Gulf of Mexico. At December 31, 2012 , the Company was in the process of drilling one exploratory well (which is excluded from the table below) and had four wells awaiting fracture stimulation. 
+Years ended December 31, 
+2012 
+2011 
+2010 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development: 
+Crude oil 
+14 
+9.70 
+36 
+32.77 
+20 
+19.37 
+Natural gas 
+— 
+— 
+— 
+— 
+1 
+0.69 
+Non-productive 
+— 
+— 
+— 
+— 
+— 
+— 
+Total 
+14 
+9.70 
+36 
+32.77 
+21 
+20.06 
+Exploration: 
+Crude oil 
+7 
+6.20 
+— 
+— 
+— 
+— 
+Natural gas 
+— 
+— 
+— 
+— 
+— 
+— 
+Non-productive 
+— 
+— 
+— 
+— 
+— 
+— 
+Total 
+7 
+6.20 
+— 
+— 
+— 
+— 
+Wells drilled within the productive boundaries of statistical plays, such as on our southern Midland basin acreage, have been classified as development wells. 
+The following table sets forth productive wells as of December 31, 2012 : 
+Crude Oil Wells 
+Natural Gas Wells 
+Gross 
+Net 
+Gross 
+Net 
+Working interest 
+103 
+84.50 
+10 
+4.30 
+Royalty interest 
+3 
+0.10 
+2 
+0.08 
+Total 
+106 
+84.60 
+12 
+4.38 
+A well is categorized as a crude oil well or a natural gas well based upon the ratio of crude oil to natural gas reserves on a Mcfe basis. However, some of our wells produce both crude oil and natural gas. 
+For the periods presented, the following table sets forth by major field(s) net production volumes and estimated proved reserves: 
+Year ended December 31, 
+Production Volumes (MBoe) 
+% of Total Proved Reserves at 12/31/2012 
+Offshore - Gulf of Mexico: 
+2012 
+2011 
+2010 
+2012 
+2011 
+2010 
+Medusa 
+464 
+641 
+593 
+28 
+% 
+27 
+% 
+33 
+% 
+Habanero 
+134 
+197 
+233 
+— 
+% 
+8 
+% 
+10 
+% 
+Shelf and other 
+340 
+551 
+616 
+4 
+% 
+4 
+% 
+7 
+% 
+Total offshore: 
+938 
+1,389 
+1,442 
+32 
+% 
+39 
+% 
+50 
+% 
+Onshore: 
+Permian basin 
+591 
+353 
+150 
+67 
+% 
+48 
+% 
+33 
+% 
+Haynesville shale 
+46 
+101 
+82 
+1 
+% 
+13 
+% 
+17 
+% 
+Total onshore: 
+637 
+454 
+232 
+68 
+% 
+61 
+% 
+50 
+% 
+Total 
+1,575 
+1,843 
+1,674 
+100 
+% 
+100 
+% 
+100 
+% 
+15 
+Table of Contents 
+Leasehold Acreage 
+The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2012 . 
+Developed 
+Undeveloped 
+Total 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Louisiana 
+1,741 
+681 
+233 
+167 
+1,974 
+848 
+Texas (a) 
+10,891 
+8,914 
+27,236 
+24,048 
+38,127 
+32,962 
+Federal onshore (b) 
+— 
+— 
+64,963 
+64,963 
+64,963 
+64,963 
+Federal waters (c) 
+44,920 
+17,136 
+23,715 
+7,599 
+68,635 
+24,735 
+Total 
+57,552 
+26,731 
+116,147 
+96,777 
+173,699 
+123,508 
+(a) 
+A portion of our Texas acreage requires continued drilling to hold the acreage for which we have included in our development plans, though the cost to renew this acreage, if necessary, is not considered material. 
+(b) 
+The Company's lease of this acreage, located in Nevada, has approximately six years remaining, and had a carrying value at December 31, 2012 of approximately $2.6 million included in the Company's unevaluated properties balance. The lease requires no drilling activity to hold the acreage, and we continue to monitor the activity of other operators conducting drilling in the area. 
+(c) 
+The Company's federal waters acreage is held by production. 
+Title to Properties 
+The Company believes that the title to its crude oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. The Company's properties are typically subject, in one degree or another, to one or more of the following: 
+• 
+royalties and other burdens and obligations, express or implied, under oil and natural gas leases, 
+• 
+overriding royalties and other burdens created by us or our predecessors in title, 
+• 
+a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect the properties or their titles, 
+• 
+back-ins and reversionary interests existing under purchase agreements and leasehold assignments, 
+• 
+liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements, 
+• 
+pooling, unitization and communitization agreements, declarations and orders, and 
+• 
+easements, restrictions, rights-of-way and other matters that commonly affect property. 
+To the extent that such burdens and obligations affect the Company's rights to production revenues, these characteristics have been taken into account in calculating Callon's net revenue interests and in estimating the size and value of its reserves. The Company believes that the burdens and obligations affecting our properties are typical within the industry for properties of the kind owned by Callon. 
+Insurance 
+In accordance with industry practice, the Company maintains insurance against some, but not all, of the operating risks to which its business is exposed. While not all inclusive, the Company's insurance policies include coverage for general liability insuring both onshore and offshore operations (including sudden and accidental pollution), physical damage to its offshore oil and natural gas properties, aviation liability, auto liability, worker's compensation, employer's liability, and maritime employers liability. The company carries control of well insurance for all offshore wells, though unless contractually bound to do so, the Company does not carry control of well insurance for onshore operations. At the depths and in the areas in which the Company operates, and in light of the vertical and horizontal drilling that it undertakes, the Company typically does not encounter high pressures or extreme drilling conditions onshore. 
+Currently, the Company has general liability insurance coverage up to $1 million per occurrence and $2 million per policy in the aggregate, which includes sudden and accidental environmental liability coverage for the effects of pollution on third parties 
+16 
+Table of Contents 
+arising from its operations. The Company's insurance policies contain high policy limits, and in most cases, deductibles (generally ranging from $0 to $1.5 million) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. In addition, the Company maintains up to $100 million in excess liability coverage, which is in addition to and triggered if the underlying liability limits have been reached. 
+The Company requires all of its third-party contractors to sign master service agreements in which they agree to indemnify the Company for injuries and deaths of the service provider's employees as well as contractors and subcontractors hired by the service provider. Similarly, the Company generally agrees to indemnify each third-party contractor against claims made by employees of the Company and the Company's other contractors. Additionally, each party generally is responsible for damage to its own property. 
+The third-party contractors that perform hydraulic fracturing operations for the Company sign master service agreements generally containing the indemnification provisions noted above. The Company does not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. However, the Company believes its general liability and excess liability insurance policies would cover foreseeable third party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies. 
+The Company re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. While based on the Company's risk analysis, it believes that it is properly insured, no assurance can be given that the Company will be able to maintain insurance in the future at rates that it considers reasonable. In such circumstances, the Company may elect to self-insure or maintain only catastrophic coverage for certain risks in the future. 
+Major Customers 
+Our production is sold generally on month-to-month contracts at prevailing prices. The following table identifies customers to whom we sold a significant percentage of our total oil and natural gas production, on an equivalent basis, during each of the 12-month periods ended: 
+December 31, 
+2012 
+2011 
+2010 
+Shell Trading Company 
+39 
+% 
+45 
+% 
+44 
+% 
+Plains Marketing, L.P. 
+15 
+% 
+17 
+% 
+20 
+% 
+Enterprise Crude Oil, LLC 
+32 
+% 
+16 
+% 
+— 
+% 
+Louis Dreyfus Energy Services 
+2 
+% 
+4 
+% 
+13 
+% 
+Other 
+12 
+% 
+18 
+% 
+23 
+% 
+Total 
+100 
+% 
+100 
+% 
+100 
+% 
+Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on Callon’s ability to market future oil and natural gas production. We are not currently committed to provide a fixed and determinable quantity of oil or gas in the near future under our contracts. 
+Corporate Offices 
+The Company’s headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned space. We also maintain leased business offices in Houston and Midland, Texas. Because alternative locations to our leased spaces are readily available, the replacement of any of our leased offices would not result in material expenditures . 
+Employees 
+Cal lon had 87 employees as of December 31, 2012 , which included 13 petroleum engineers and four petroleum geoscientists. None of the Company’s employees are currently represented by a union, and the Company believes that it has good relations with its employees. 
+17 
+Table of Contents 
+Regulations 
+General. The oil and natural gas industry is subject to regulation at the federal, state and local level, and some of the laws, rules and regulations that govern our operations carry substantial penalties for non-compliance. Rules and regulations affecting the oil and natural gas industry are under constant review for amendment or expansion, which could increase the regulatory burden and the potential for financial sanctions for noncompliance. This regulatory burden increases our cost of doing business and, consequently, affects our profitability. 
+Exploration and Production . Our operations are subject to federal, state and local regulations that include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds and letters of credit) covering drilling and well operations. Other activities subject to regulation are: 
+• 
+the location and spacing of wells, 
+• 
+the method of drilling and completing and operating wells, 
+• 
+the rate and method of production, 
+• 
+the surface use and restoration of properties upon which wells are drilled and other exploration activities, 
+• 
+notice to surface owners and other third parties, 
+• 
+the plugging and abandoning of wells, 
+• 
+the discharge of contaminants into water and the emission of contaminants into air, 
+• 
+the disposal of fluids used or other wastes obtained in connection with operations, 
+• 
+the marketing, transportation and reporting of production, and 
+• 
+the valuation and payment of royalties. 
+For instance, our OCS leases in federal waters are administered by three Bureaus of the Department of Interior "DOI". In response to concerns that the former MMS revenue-generating and resource development functions were at odds with its safety and environmental regulatory functions, the DOI reorganized the MMS into three separate agencies: the BOEM, to be the resource manager for conventional and renewable energy and mineral resources on the OCS; the BSEE, to promote and enforce safety in offshore energy exploration and production operations; and the ONRR, to collect and distribute royalties, rents, fees and other revenues, including the development of regulations with respect to revenue valuation and collection and enforcement activities. In this “Exploration and Production” section, we refer to actions of one or more of the foregoing agencies as actions of “the DOI Bureaus”. 
+The DOI Bureaus require compliance with detailed regulations and orders. Lessees must obtain DOI Bureau approval for exploration, exploitation and production plans and applications for permits to drill prior to the commencement of such operations. Since the April 20, 2010 blowout and oil spill at the BP Deepwater Horizon Macondo oil well, the DOI Bureaus have issued numerous rules, Notices to Lessees and other guidance documents augmenting the existing regulations with more stringent safety, engineering and environmental requirements. The DOI Bureaus have also issued a rule requiring that all operators in the OCS formulate detailed Safety and Environmental Management Systems to improve the safety of their operations on the OCS. Current DOI Bureau regulations restrict the flaring or venting of natural gas, and prohibit the flaring of liquid hydrocarbons and oil without prior authorization. The DOI Bureaus are considering whether to require flaring rather than venting, where practical, to reduce the potential effect of greenhouse gas emissions. 
+DOI Bureau policies concerning the volume of production that a lessee must have to maintain an offshore lease beyond its primary term also are applicable to Callon. Similarly, the DOI Bureaus have promulgated other regulations and Notices to Lessees governing the plugging and abandonment of wells located offshore and the installation and decommissioning of production facilities. To cover the various obligations of lessees on the OCS, the DOI Bureaus generally requires that lessees post bonds, letters of credit, or other acceptable assurances that such obligations will be met. The cost of these bonds or other surety can be substantial, and there is no assurance that bonds or other surety can be obtained in all cases. Under some circumstances, the DOI Bureaus may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial conditions and results of operations. 
+As stated above, the April 20, 2010 blowout and oil spill at the BP Deepwater Horizon oil rig has prompted the federal government to impose heightened regulation of oil and natural gas exploration and production on the OCS. Especially with respect to deepwater operations, the DOI Bureaus have issued rules that are more stringent than the rules issued by the MMS, and have announced their intention to issue additional safety rules and be more scrupulous in implementing existing environmental requirements in the future. Legislation has been introduced in the United States Congress to toughen the regulation of oil and natural gas exploration and production on the OCS. In addition, the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, whose members were appointed by President Obama, issued a report proposing, among other things, fundamental reform of the regulation of oil and natural gas exploration and production on the OCS. The tightening of regulation on the OCS could impose 
+18 
+Table of Contents 
+higher costs on, and render it more difficult to timely obtain regulatory approval of our proposed activities on the OCS, especially as to deepwater projects. 
+Operations conducted on federal or state oil and natural gas leases must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the DOI Bureaus or other appropriate federal or state agencies. 
+Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. If these regulations change, we could face higher transmission costs for our production and, possibly, reduced access to transmission capacity. 
+Various proposals and proceedings that might affect the petroleum industry are pending before Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the courts. The industry historically has been heavily regulated and we can offer you no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations. 
+We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, earnings or competitive position. 
+Environmental Regulation . Various federal, state and local laws and regulations concerning the release of contaminants into the environment, including the discharge of contaminants into water and the emission of contaminants into the air, the generation, storage, treatment, transportation and disposal of wastes, and the protection of public health, welfare, and safety, and the environment, including natural resources, affect our exploration, development and production operations, including operations of our processing facilities. We must take into account the cost of complying with environmental regulations in planning, designing, drilling, constructing, operating and abandoning wells. Regulatory requirements relate to, among other things, the handling and disposal of drilling and production waste products, the control of water and air pollution and the removal, investigation, and remediation of petroleum-product contamination. In addition, our operations may require us to obtain permits for, among other things, 
+• 
+air emissions, 
+• 
+discharges into surface waters (including wetlands), and 
+• 
+the construction and operations of underground injection wells or surface pits to treat, re-use or dispose of produced water and other nonhazardous oilfield wastes. 
+In the event of an unauthorized discharge (e.g., to land or water), emission (e.g., to air) or other activity, we may be liable for, among other things, penalties, costs and damages, and subject to injunctive relief, and we could be required to cleanup or mitigate the environmental impacts of those discharges, emissions or activities. Also, under federal, and certain state, laws, the present and certain past owners and operators of a site, and persons that treated, disposed of or arranged for the disposal of hazardous substances found at a site, may be liable, without regard to fault or the legality of the original conduct, for the release of hazardous substances into the environment and damage to natural resources caused by such release. The Environmental Protection Agency, state environmental agencies and, in some cases third parties are authorized to take actions in response to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such actions. We therefore could be required to remove or remediate previously disposed wastes and remediate contamination, including contamination in surface water, soil or groundwater, caused by disposal of that waste, irrespective of whether disposal or release were unlawful. We could be responsible for wastes disposed of or released by us or prior owners or operators at properties owned or leased by us or at locations where wastes have been taken for disposal also irrespective of whether disposal or release were authorized. We could also be required to suspend or cease operations in contaminated areas, or to perform remedial well plugging operations or cleanups to prevent future contamination. 
+Federal, and certain state, laws also impose duties and liabilities on certain “responsible parties” related specifically to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. These laws assign liability, which generally is joint and several, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses and limitations exist to the liability imposed under these laws, they are limited. In the event of an oil discharge or substantial threat of discharge, we could be liable for costs and damages. 
+19 
+Table of Contents 
+The Environmental Protection Agency and various state agencies have limited the disposal options for hazardous and nonhazardous wastes thereby increasing the costs of disposal. Furthermore, certain wastes generated by our oil and natural gas operations that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes and, therefore, be subject to considerably more rigorous and costly operating and disposal requirements. 
+Federal and state occupational safety and health laws require us to organize information about hazardous materials used, released or produced in our operations. Certain portions of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in federal workplace standards. 
+There are federal and certain state laws that impose restrictions on activities adversely affecting the habitat of certain plant and animal species. In the event of an unauthorized impact or taking of a protected species or its habitat, we could be liable for penalties, costs and damages, and subject to injunctive relief, and we could be required to mitigate those impacts. A critical habitat or suitable habitat designation also could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. 
+Oil and natural gas exploration and production activities are being subjected to additional regulatory scrutiny under the Clean Air Act (“CAA”). On April 17, 2012, the EPA issued final rules to subject oil and gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured gas wells and also existing gas wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from certain compressors, controllers, dehydrators, storage tanks, natural gas processing plants and other equipment based upon equipment types, locations, and emission thresholds. These rules may require changes to our operations, including the installation of new equipment to control emissions. 
+We have made and will continue to make expenditures to comply with environmental regulations and requirements. These are necessary costs of doing business within the oil and natural gas industry. Although we are not fully insured against all environmental risks, we maintain insurance coverage which we believe is customary in the industry. Moreover, it is possible that other developments, such as stricter and more comprehensive environmental laws and regulations, as well as claims for damages to property or persons resulting from company operations, could result in substantial costs and liabilities. We believe we are in compliance with existing environmental regulations, and that, absent the occurrence of an extraordinary event the effect of which cannot be predicted, any noncompliance will not have a material adverse effect on our operations or earnings. 
+Greenhouse Gas (“GHG”) Regulation. Although federal legislation regarding the control of greenhouse gasses, or GHGs, thus far has been unsuccessful, the EPA has moved forward with rulemaking to regulate GHGs as pollutants under the CAA. These GHG regulations may require us to incur increased operating costs and may have an adverse effect on demand for the oil and natural gas we produce. 
+The EPA, as of January 2, 2011, requires the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs in a multi-step process, with the largest sources first subject to permitting. Those permitting provisions, should they become applicable to our operations, could require controls or other measures to reduce GHG emissions from new or modified sources, and we could incur additional costs to satisfy those requirements. On November 30, 2010, EPA published a rule establishing GHG reporting requirements for sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions if the total emissions within a basin exceed 25,000 metric tons CO 2 equivalent per year. Although this rule does not limit the amount of GHGs that can be emitted, it will require us to incur costs to monitor, keep records of, and potentially report GHG emissions associated with our operations if the reporting threshold is reached with production growth. 
+In addition to federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These potential regional and state initiatives may result in so-called "Cap-and-Trade programs", under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, such as by being required to purchase or to surrender allowances for GHGs resulting from our operations. The federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors. 
+20 
+Table of Contents 
+Application of the Safe Drinking Water Act to Hydraulic Fracturing. Congress has considered but has not passed legislation to amend the federal Safe Drinking Water Act to remove the exemption for hydraulic fracturing operations and require reporting and disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Sponsors of these bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. A number of state, local and regional regulatory authorities have or are considering hydraulic fracturing regulation. For example, Texas has adopted regulations requiring the disclosure of hydraulic fracturing chemicals. Potential federal as well as existing and potential state regulation could cause us to incur substantial compliance costs, and the requirement could negatively affect our ability to conduct fracturing activities on our assets. 
+In addition, the EPA has recently been taking actions to assert federal regulatory authority over hydraulic fracturing using diesel under the Safe Drinking Water Act's Underground Injection Control Program. Further, in March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. A progress report was issued in December 2012, with final results expected in 2014. In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming. This study remains subject to review. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Consequently, these studies and initiatives could spur further legislative or regulatory action regarding hydraulic fracturing or other production operations. Further, the BLM has indicated that it will engage in rulemaking to regulate hydraulic fracturing on federal lands. 
+Further, EPA has announced an initiative under the Toxic Substances Control Act (“TSCA”) to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals. 
+All of the acreage and undeveloped reserves within the Permian basin are subject to hydraulic fracturing procedures as the process is required to economically develop the Wolfberry formation. The hydraulic fracturing process is integral to the Company's overall drilling and completion costs in the Permian basin and represented approximately 34% or $0.8 million of the total drilling/completion costs per vertical well drilled during 2012. 
+The hydraulic fracturing activity is limited to the oil and natural gas bearing formations, which are found at depths ranging between 6,000 and 12,000 feet from the surface in Midland, Ector and Upton counties, Texas. The Railroad Commission of Texas has defined potable water sources in this area as usable-quality ground water from the surface to a depth of 250 feet for our acreage in Midland and Ector counties and to a depth of 425 feet for our acreage in Upton counties. 
+The Company diligently reviews best practices and industry standards, and complies with all regulatory requirements in the protection of these potable water sources. Protective practices include, but are not limited to, setting multiple strings of protection pipe across the potable water sources and cementing these pipes from setting depth to surface, continuously monitoring the hydraulic fracturing process in real time, and disposing of all non-commercially produced fluids in certified disposal wells at depths below the potable water sources. 
+Based on current drilling techniques, a typical fracturing procedure for a vertical well in the Wolfberry formation uses approximately 1.8 million gallons of fresh water, approximately 1.2 million pounds of sand and other elements including enzymes and guar, a common food additive. Horizontal wells typically use 9.5 million gallons of water and approximately 6.2 million pounds of sand. 
+In compliance with the law enacted in Texas in June 2011 and regulations adopted in December 2011, the Company will disclose hydraulic fracturing data to the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission chemical registry effective January 2, 2012. This disclosure is required for each chemical ingredient that is subject to the requirements of OSHA regulations, as well as the total volume of water used in the hydraulic fracturing treatment. A copy of the completed form is uploaded into the Chemical Disclosure Registry also known as FracFocus, which is a publically accessible website. 
+There have not been any incidents, citations or suits related to the Company's hydraulic fracturing activities involving environmental concerns. 
+The Federal Water Pollution Control Act, also known as the “Clean Water Act” and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. 
+21 
+Table of Contents 
+Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, we may be liable for penalties and cleanup and response costs. 
+Surface Damage Statutes (“SDAs”) . In addition, a number of states and some tribal nations have enacted SDAs. These laws are designed to compensate for damage caused by oil and gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments to the operator in connection with exploration and operating activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs. 
+Mineral Lease Act of 1920 (“Mineral Act”) . The Mineral Act prohibits direct or indirect ownership of any interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign corporation except through stock ownership in a corporation formed under the laws of the United States or of any U.S. state or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or corporations of the United States. If these restrictions are violated, the oil and gas lease or leases can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the Bureau of Land Management ("BLM") (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. The Company owns interests in numerous federal onshore oil and natural gas leases. It is possible that holders of the Company's equity interests may be citizens of foreign countries, which could be determined to be citizens of a non-reciprocal country under the Mineral Act. In such event, the federal onshore oil and gas leases held by the Company could be subject to cancellation based on such determination. 
+Other Regulations . If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements. Certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the BLM, the Bureau of Ocean Energy Management, the Bureau of Safety and Environmental Enforcement, or other appropriate federal, state, or tribal agencies. 
+Commitments and Contingencies 
+The Company's activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement polices included, and claims for damages to property, employees, other persons, and the environment resulting from the Company's operations could have on its activities. See Note 15 for additional information. 
+Available Information 
+We make available free of charge on our Internet web site (www.callon.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC. You may read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, like Callon, that file electronically with the SEC. 
+We also make available within the Investors section of our Internet web site our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation and Nominating and Governance Committee Charters, which have been approved by our board of directors. We will make timely disclosure by a Current Report on Form 8-K and on our web site of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also available, free of charge by writing us at: Chief Financial Officer, Callon Petroleum Company, P.O. Box 1287, Natchez, MS 39121. 
+22 
+Table of Contents 
+Item 1A. Risk Factors 
+Risk Factors 
+Depressed oil and natural gas prices may adversely affect our results of operations and financial condition . Our success is highly dependent on prices for oil and natural gas, which are extremely volatile, and the oil and natural gas markets are cyclical. Extended periods of low prices for oil or natural gas will have a material adverse effect on us. The prices of oil and natural gas depend on factors we cannot control such as weather, economic conditions, and levels of production, actions by OPEC and other countries and government actions. Prices of oil and natural gas will affect the following aspects of our business: 
+• 
+our revenues, cash flows and earnings; 
+• 
+the amount of oil and natural gas that we are economically able to produce; 
+• 
+our ability to attract capital to finance our operations and the cost of the capital; 
+• 
+the amount we are allowed to borrow under our Credit Facility; 
+• 
+the profit or loss we incur in exploring for and developing our reserves; and 
+• 
+the value of our oil and natural gas properties. 
+Natural gas prices have been depressed recently and have the potential to remain depressed for the next several years, which may have an adverse effect on our financial condition and results of operations. Natural gas prices have been depressed for the last several years as a result of over-supply caused by, among other things, increased drilling in unconventional reservoirs, reduced economic activity associated with a recession and weather conditions. We expect natural gas prices to be depressed during the foreseeable future. Approximately 23% of our estimated net proved reserves at December 31, 2012 are natural gas, and 38% of our production in 2012 was natural gas. A sustained reduction in natural gas prices could have an adverse effect on our results of operations and financial condition. 
+If oil and natural gas prices decrease or remain depressed for extended periods of time, we may be required to take additional writedowns of the carrying value of our oil and natural gas properties. We may be required to writedown the carrying value of our oil and natural gas properties when oil and natural gas prices are low or if we have substantial downward adjustments to our estimated net proved reserves, increases in our estimates of development costs or if we experience deterioration in our exploration results. Under the full-cost method, which we use to account for our oil and natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the present value, discounted at 10%, of future net cash flows from estimated net proved reserves, using the preceding 12-months' average oil and natural gas prices based on closing prices on the first day of each month, plus the lower of cost or fair market value of our unproved properties. If net capitalized costs of our oil and natural gas properties exceed this limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders' equity. We review the carrying value of our properties quarterly, based on the pricing noted above. Once incurred, a writedown of oil and natural gas properties is not reversible at a later date, even if prices increase. See Note 14 to our Consolidated Financial Statements. 
+Our actual recovery of reserves may substantially differ from our proved reserve estimates. This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. Additionally, our interpretations of the rules governing the estimation of proved reserves could differ from the interpretation of staff members of regulatory authorities resulting in estimates that could be challenged by these authorities. 
+Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas. We incorporate many factors and assumptions into our estimates including: 
+• 
+Expected reservoir characteristics based on geological, geophysical and engineering assessments; 
+• 
+Future production rates based on historical performance and expected future operation investment activities; 
+• 
+Future oil and natural gas prices and quality and locational differences; and 
+• 
+Future development and operating costs. 
+23 
+Table of Contents 
+You should not assume that any present value of future net cash flows from our producing reserves contained in this Form 10-K represents the market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at December 31, 2012 on average 12-month prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. At December 31, 2012 , approximately 14% of the discounted present value of our estimated net proved reserves consisted of PUDs. PUDs represented 52% of total proved reserves by volume, and approximately 18% of our PUDs were attributable to our deepwater property. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these undeveloped reserves and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general. 
+Information about reserves constitutes forward-looking information. See “Forward-Looking Statements” for information regarding forward-looking information. 
+Unless we are able to replace reserves that we have produced, our cash flows and production will decrease over time. The high-rate production characteristics of our Gulf of Mexico properties subject us to high reserve replacement needs. In general, the volume of production from oil and natural gas properties declines as reserves are depleted. The decline rates depend on reservoir characteristics. Gulf of Mexico reservoirs tend to be recovered quickly through production with associated steep declines, while declines in other regions after initial flush production tend to be relatively low. Our Gulf of Mexico, deepwater properties accounted for approximately 38% of our production which included the Habanero property during 2012 and 28% of our estimated proved reserves at December 31, 2012 excluding the Habanero property. Similarly, our Gulf of Mexico shelf properties accounted for approximately 22% of our production during 2012 and 4% of our estimated proved reserves at December 31, 2012 . Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. Our future natural gas and oil production is highly dependent upon our level of success in finding or acquiring additional reserves at a unit cost that is sustainable at prevailing commodity prices. Without successful exploration or acquisition activities, our reserves, production and revenues will decline. 
+Exploring for, developing, or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop, or acquire additional reserves, or may not be able to make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable. As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures, currently expected to be in excess of three times the cost, as compared to the drilling of a traditional vertical well. The incremental capital expenditures are the result of greater measured depths and additional hydraulic fracture stages in horizontal wellbores. We cannot assure you that our future exploitation, exploration, development, and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. We cannot assure you that we will be able to find and develop or acquire additional reserves at an acceptable cost. 
+The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget. Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies, water or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. Increasing levels of exploration and production may increase the demand for oilfield services and equipment, and the costs of these services and equipment may increase, while the quality of these services and equipment may suffer. The unavailability or high cost of drilling rigs, pressure pumping equipment, supplies or qualified personnel can materially and adversely affect our operations and profitability. 
+A significant portion of our production and reserves is concentrated in our deepwater offshore property, and any production problems or inaccuracies in reserve estimates related to this property would adversely impact our business. During 2012 , approximately 29% of our daily production came from our Medusa field, which is currently our only deepwater property located in the Gulf of Mexico. In addition, at December 31, 2012 , approximately 28% of our total net proved reserves were located within this field. If mechanical problems, storms or other events curtailed a substantial portion of this production, or if the actual reserves associated with this producing property are less than our estimated reserves, our results of operations and financial condition could be adversely affected. 
+24 
+Table of Contents 
+Our exploration projects increase the risks inherent in our oil and natural gas activities. We may seek to replace reserves through exploration, where the risks are greater than in acquisitions and development drilling. During 2012, we purchased 24,328 net acres in the northern portion of the Midland basin, an area that has seen only limited development activity. We expect to conduct substantial exploration of this acreage over the next several years. Although we have been successful in exploration in the past, we cannot assure you that we will continue to increase reserves through exploration or at an acceptable cost. Additionally, we are often uncertain as to the future costs and timing of drilling, completing and producing wells. Our exploration drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including: 
+• 
+receipt of additional seismic data or other geophysical data or the reprocessing of existing data; 
+• 
+material changes in oil or natural gas prices; 
+• 
+the costs and availability of drilling rigs; 
+• 
+the success or failure of wells drilled in similar formations or which would use the same production facilities; 
+• 
+availability and cost of capital; 
+• 
+changes in the estimates of the costs to drill or complete wells; 
+• 
+our ability to attract other industry partners to acquire a portion of the working interest to reduce exposure to costs and drilling risks; 
+• 
+decisions of our joint working interest owners; and 
+• 
+changes to governmental regulations. 
+Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive deposits will not be discovered. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return. Our ability to achieve our target results are dependent upon the current and future market prices for oil and natural gas, costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost. 
+In addition, we may not be successful in controlling our drilling and production costs to improve our overall return. The cost of drilling, completing and operating a well is often uncertain and cost factors can adversely affect the economics of a project. We cannot predict the cost of drilling, and we may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including: 
+• 
+unexpected drilling conditions; 
+• 
+pressure or irregularities in formations; 
+• 
+equipment failures or accidents and shortages or delays in the availability of drilling rigs and the delivery of equipment; and 
+• 
+compliance with governmental requirements. 
+We may be unable to integrate successfully the operations of future acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. Our business may include producing property acquisitions that would include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from any acquisitions we may complete in the future. In addition, failure to assimilate recent and future acquisitions successfully could adversely affect our financial condition and results of operations. Our acquisitions may involve numerous risks, including: 
+• 
+operating a larger combined organization and adding operations; 
+• 
+difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new business segment or geographic area; 
+• 
+risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated; 
+• 
+loss of significant key employees from the acquired business: 
+• 
+diversion of management's attention from other business concerns; 
+• 
+failure to realize expected profitability or growth; 
+• 
+failure to realize expected synergies and cost savings; 
+• 
+coordinating geographically disparate organizations, systems and facilities; and 
+• 
+coordinating or consolidating corporate and administrative functions. 
+25 
+Table of Contents 
+Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. 
+We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. We are actively seeking to acquire additional acreage in Texas or other regions in the future. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating and capital costs and potential environmental and other liabilities. Although we conduct a review of properties we acquire which we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms. 
+There is competition for available oil and natural gas properties. Our competitors include major oil and gas companies, independent oil and gas companies and financial buyers. Some of our competitors may have greater and more diverse resources than we do. High commodity prices and stiff competition for acquisitions have in the past, and may in the future, significantly increase the cost of available properties. The increased competition and rising prices for available properties could limit or impede our ability to identify acquisition opportunities that are economic for a company our size and that are necessary to grow our reserves or replace reserves produced. 
+We do not operate and have limited influence over the operations of our deepwater property. Our lack of control could result in the following: 
+• 
+the operator may initiate exploration or development at a faster or slower pace than we prefer or that we anticipate in preparing our reserve estimates; 
+• 
+the operator may propose to drill more wells or build more facilities on a project than we have funds for or that we deem appropriate, which may mean that we are unable to participate in the project or share in the revenues generated by the project even though we paid our share of exploration costs; and 
+• 
+if an operator refuses to initiate a project, we may be unable to pursue the project. 
+Any of these events could materially impact the value of our non-operated properties. 
+Weather, unexpected subsurface conditions, and other unforeseen operating hazards may adversely impact our ability to conduct business. There are many operating hazards in exploring for and producing oil and natural gas, including: 
+• 
+our drilling operations may encounter unexpected formations or pressures, which could cause damage to equipment or personal injury; 
+• 
+we may experience equipment failures which curtail or stop production; 
+• 
+we could experience blowouts or other damages to the productive formations that may require a well to be re-drilled or other corrective action to be taken; 
+• 
+hurricanes, storms and other weather conditions could cause damages to our production facilities or wells. 
+Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas-leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures. 
+26 
+Table of Contents 
+If we experience any of these problems, it could affect well bores, platforms, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses in excess of our insurance coverage as a result of: 
+• 
+injury or loss of life; 
+• 
+severe damage to and destruction of property, natural resources and equipment; 
+• 
+pollution and other environmental damage; 
+• 
+clean-up responsibilities; 
+• 
+regulatory investigation and penalties; 
+• 
+suspension of our operations; and 
+• 
+repairs to resume operations. 
+Offshore operations are also subject to a variety of additional operating risks peculiar to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for development or leasehold acquisitions, or result in loss of equipment and properties. 
+We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with the wells for which we are the operator. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under federal and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury. In March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. A progress report was issued in December 2012, with final results expected in 2014. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative, could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. 
+We cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable to cover our possible losses from operating hazards. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and results of operations. 
+Factors beyond our control affect our ability to market production and our financial results. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. These factors could negatively affect our ability to market all of the oil or natural gas we produce. In addition, we may be unable to obtain favorable prices for the oil and natural gas we produce. These factors include: 
+• 
+the extent of domestic production and imports of oil and natural gas; 
+• 
+the proximity of the natural gas production to natural gas and NGL pipelines; 
+• 
+the availability of pipeline capacity; 
+• 
+the demand for oil and natural gas by utilities and other end users; 
+• 
+the availability of alternative fuel sources; 
+• 
+the effects of inclement weather; 
+• 
+state and federal regulation of oil and natural gas marketing; and 
+• 
+federal regulation of natural gas sold or transported in interstate commerce. 
+In particular, in areas with increasing non-conventional shale drilling activity, capacity may be limited and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built. 
+Part of our strategy involves drilling in new or emerging shale formations using horizontal drilling and completion techniques. The results of our planned drilling program in these formations may be subject to more uncertainties than conventional drilling programs in more established formations and may not meet our expectations for reserves or production. The results of our recent horizontal drilling efforts in new or emerging formations, including the Wolfcamp shale, Cline shale, and Mississippian lime in the Permian basin, are generally more uncertain than drilling results in areas that are developed and have established production. Because new or emerging formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis predict our future drilling results. The ultimate success of these drilling and completion strategies and techniques will be better evaluated over time as more wells are drilled and production profiles are better established. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results are less than anticipated 
+27 
+Table of Contents 
+or we are unable to execute our drilling program because of capital constraints, access to gathering systems and takeaway capacity or otherwise, and/or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material writedowns of unevaluated properties and the value of our undeveloped acreage could decline in the future. 
+The loss of key personnel could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas from proved properties and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees and our third party consultants, none of whom are subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business. 
+We may not be insured against all of the operating risks to which our business in exposed. In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We cannot assure you that our insurance will be adequate to cover losses or liabilities. We experienced Gulf of Mexico production interruption in 2005, 2006, 2007, and 2012 from Hurricanes Katrina, Rita, and Isaac and in 2008 and 2009 from Hurricanes Gustav and Ike for which we had no production interruption insurance. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. No assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable and may elect none or minimal insurance coverage. The occurrence of a significant event, not fully insured or indemnified against, could have a material adverse affect on our financial condition and operations. 
+Competitive industry conditions may negatively affect our ability to conduct operations. We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies as well as numerous independents, including many that have significantly greater resources. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development. Factors that affect our ability to compete in the marketplace include: 
+• 
+our access to the capital necessary to drill wells and acquire properties; 
+• 
+our ability to acquire and analyze seismic, geological and other information relating to a property; 
+• 
+our ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property; 
+• 
+our ability to procure materials, equipment and services required to explore, develop and operate our properties, including the ability to procure fracture stimulation services on wells drilled; and 
+• 
+our ability to access pipelines, and the location of facilities used to produce and transport oil and natural gas production. 
+Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. 
+During 2010, the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”). Among other things, the Act requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market. 
+In its rulemaking under the new legislation, the CFTC has issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions); the CFTC's final rule was set aside by the U.S. District Court for the District of Columbia on September 28, 2012 and remanded to the CFTC to resolve ambiguity as to whether statutory requirements for such limits to be determined necessary and appropriate were satisfied. As a result, the rule has not yet taken effect, although the CFTC has indicated that it intends to appeal the court's decision and that it believes the Dodd-Frank Act requires it to impose position limits. The impact of such regulations upon our business is not yet clear. Certain of our hedging and trading activities and those of our counterparties may be subject to the position limits, which may reduce our ability to enter into hedging transactions. 
+In addition, the Act does not explicitly exempt end users (such as us) from the requirement to use cleared exchanges, rather than hedging over-the-counter, and the requirements to post margin in connection with hedging activities. While it is not possible at this time to predict when the CFTC will finalize certain other related rules and regulations, the Act and related regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although whether these requirements will apply to our business is uncertain at this time. If the regulations ultimately adopted require that we post margin for our hedging activities or require our counterparties to hold margin or maintain 
+28 
+Table of Contents 
+capital levels, the cost of which could be passed through to us, or impose other requirements that are more burdensome than current regulations, our hedging would become more expensive and we may decide to alter our hedging strategy. 
+The financial reform legislation may also require the counterparties to derivative instruments to spin off some of their derivative activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts reduce the availability of derivatives to protect against risks we encounter, restrict our flexibility in conducting trading and hedging activity and increase our exposure to less creditworthy counterparties. If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural-gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows. 
+We may not have production to offset hedges; by hedging, we may not benefit from price increases. Part of our business strategy is to reduce our exposure to the volatility of oil and natural gas prices by hedging a portion of our production. In a typical hedge transaction, we will have the right to receive from the other parties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the other parties this difference multiplied by the quantity hedged. Additionally, we are required to pay the difference between the floating price and the fixed price when the floating price exceeds the fixed price regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of production. Hedging will also prevent us from receiving the full advantage of increases in oil or natural gas prices above the fixed amount specified in the hedge. 
+We also enter into price “collars” to reduce the risk of changes in oil and natural gas prices. Under a collar, no payments are due by either party so long as the market price is above a floor set in the collar and below a ceiling. If the price falls below the floor, the counter-party to the collar pays the difference to us and if the price is above the ceiling, we pay the counter-party the difference. Another type of hedging contract we have entered into is a put contract. Under a put, if the price falls below the set floor price, the counter-party to the contract pays the difference to us. See “Quantitative and Qualitative Disclosures About Market Risks” for a discussion of our hedging practices. 
+Compliance with environmental and other government regulations could be costly and could negatively impact production. Our operations are subject to numerous laws and regulations governing the operation and maintenance of our facilities and the discharge of materials into the environment or otherwise relating to environmental protection. For a discussion of the material regulations applicable to us, see “Regulations.” These laws and regulations may: 
+• 
+require that we acquire permits before commencing drilling; 
+• 
+impose operational, emissions control and other conditions on our activities; 
+• 
+restrict the substances that can be released into the environment in connection with drilling and production activities; 
+• 
+limit or prohibit drilling activities on protected areas such as wetlands, wilderness areas or coral reefs; and 
+• 
+require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or dismantling abandoned production facilities. 
+Under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of and increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. We could also be affected by more stringent laws and regulations adopted in the future, including any related climate change, greenhouse gases and hydraulic fracturing. Under the common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or we may be required to cease production from properties in the event of environmental incidents. 
+29 
+Table of Contents 
+Climate change legislation or regulations restricting emissions of “greenhouse gasses” could result in increased operating costs and reduced demand for the oil and natural gas we produce. The EPA has adopted its so-called "GHG tailoring rule" that will phase in federal PSD permit requirements for greenhouse gas emissions from new sources and modification of existing sources, federal Title V operating permit requirements for all sources, based upon their potential to emit specific quantities of GHGs. These permitting provisions to the extent applicable to our operations could require us to implement emission controls or other measures to reduce GHG emissions and we could incur additional costs to satisfy those requirements. 
+In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA published its amendments to the greenhouse gas reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities we operate. Reporting of greenhouse gas emissions from such facilities is required on an annual basis if the total emissions within a basin exceed 25,000 metric tons CO 2 equivalent per year. We will have to incur costs associated with this monitoring obligation and potentially additional reporting costs if production growth triggers the emission threshold. 
+In addition, the United States Congress has considered legislation to reduce emissions of GHGs and many states have already taken or have considered legal measures to reduce or measure GHG emissions, often involving the planned development of GHG emission inventories and/or cap and trade programs. Most of these cap and trade programs would require major sources of emissions or major producers of fuels to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. These allowances would be expected to escalate significantly in cost over time. The adoption and implementation of any legislation or regulatory programs imposing GHG reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGS associated with our operations or could adversely affect demand for the oil and natural gas that we produce. 
+Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects. In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production activities either because of climate-related damages to our facilities in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect affect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. Should drought conditions occur, our ability to obtain water in sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. 
+Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions but is not subject to regulation at the federal level (except for fracturing activity involving the use of diesel). The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. A progress report was issued in December 2012, and final results anticipated in 2014. In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming; this study remains subject to review. A committee of the U.S. House of Representatives conducted an investigation of hydraulic fracturing practices. Legislation was introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states and local or regional regulatory authorities have adopted or are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, New York has imposed a de facto moratorium on the issuance of permits for high-volume, horizontal hydraulic fracturing until state-administered environmental studies are finalized. Further, Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed. While we have no operations in either New York or Pennsylvania, any other new laws or regulations that significantly restrict hydraulic fracturing in areas in which we do operate could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect the determination of whether a well is commercially viable. Further, EPA has announced an initiative under TSCA to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals, and the BLM has indicated that it will continue with rulemaking to regulate hydraulic fracturing on federal lands. In addition, if hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional 
+30 
+Table of Contents 
+permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities. 
+Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation. In recent years, the Obama administration's budget proposals and other proposed legislation have included the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to (1) the repeal of the percentage depletion allowance for oil and gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for U.S. production activities and (4) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and gas within the United States. It is unclear whether any such changes will be enacted or how soon any such changes would become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could negatively affect the Company's financial condition and results of operations. 
+There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected. Our management, including our Chief Executive Officer and Chief Financial Officer, do not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations. 
+ITEM 1B. Unresolved Staff Comments 
+None. 
+ITEM 3. Legal Proceedings 
+We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our financial position or results of operations. 
+ITEM 4. Mine Safety Disclosures 
+Not applicable. 
+31 
+Table of Contents 
+PART II. 
+ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+The Company’s common stock trades on the New York Stock Exchange under the symbol "CPE". The following table sets forth the high and low sale prices per share as reported for the periods indicated. 
+Stock Price 
+2012 
+High 
+Low 
+First quarter 
+ended 
+March 31, 2012 
+$ 
+7.95 
+$ 
+5.09 
+Second quarter 
+ended 
+June 30, 2012 
+6.45 
+3.80 
+Third quarter 
+ended 
+September 30, 2012 
+6.55 
+4.11 
+Fourth quarter 
+ended 
+December 31, 2012 
+6.36 
+4.05 
+2011 
+First quarter 
+ended 
+March 31, 2011 
+$ 
+9.36 
+$ 
+5.81 
+Second quarter 
+ended 
+June 30, 2011 
+8.04 
+5.93 
+Third quarter 
+ended 
+September 30, 2011 
+7.73 
+3.79 
+Fourth quarter 
+ended 
+December 31, 2011 
+5.99 
+3.02 
+As of March 1, 2013 the Company had approximately 3,229 common stockholders of record. 
+The Company has never paid dividends on its common stock, and intends to retain its cash flow from operations for the future operation and development of its business. In addition, the Company’s Credit Facility and the terms of our outstanding debt prohibit the payment of cash dividends on our common stock. 
+During the fourth quarter of 2012 , neither the Company nor any affiliated purchasers made repurchases of Callon’s equity securities. 
+Equity Compensation Plan Information 
+The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2012 (securities amounts are presented in thousands). 
+Outstanding Options 
+Plan Category 
+Number of securities to be issued upon exercise of outstanding options 
+Weighted-average exercise price of outstanding options 
+Number of securities remaining available for future issuance under equity compensation plans 
+Equity compensation plans approved by security holders 
+37 
+$ 
+13.51 
+1,669 
+Equity compensation plans not approved by security holders 
+30 
+7.90 
+— 
+Total 
+67 
+11.82 
+1,669 
+For additional information regarding the Company’s benefit plans and share-based compensation expense, see Notes 8 and 9 to the Consolidated Financial Statements. 
+32 
+Table of Contents 
+Performance Graph 
+The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the New York Stock Exchange Market Index and of the Morningstar Group Index (consisting of independent oil and gas drilling and exploration companies) from December 31, 2007 , through December 31, 2012 . The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing. 
+For the Year Ended December 31, 
+Company/Market/Peer Group 
+2007 
+2008 
+2009 
+2010 
+2011 
+2012 
+Callon Petroleum Company 
+$ 
+100.00 
+$ 
+15.81 
+$ 
+9.12 
+$ 
+35.99 
+$ 
+30.21 
+$ 
+28.57 
+NYSE Composite Index 
+100.00 
+60.86 
+78.25 
+88.89 
+85.63 
+99.47 
+Morningstar Group Index 
+100.00 
+39.51 
+71.28 
+74.52 
+64.64 
+71.97 
+33 
+Table of Contents 
+ITEM 6. Selected Financial Data 
+The following table sets forth, as of the dates and for the periods indicated, selected financial information about us. The financial information for each of the five years in the period ended December 31, 2012 has been derived from our audited Consolidated Financial Statements for such periods. The information should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of our future results. The information included in this table for the year ended December 31, 2011 include the effects of corrections on the previously reported financial statements, as further discussed in Note 1 to the Consolidated Financial Statements included in Part II, Item 8 of this filing. 
+For the year ended December 31, 
+2012 
+2011 
+2010 
+2009 
+2008 
+Statement of Operations Data: 
+(In thousands, except per share amounts) 
+Operating revenues: 
+Oil and natural gas sales 
+$ 
+110,733 
+$ 
+127,644 
+$ 
+89,882 
+$ 
+101,259 
+$ 
+141,312 
+Medusa BOEM royalty recoupment (a) 
+— 
+— 
+— 
+40,886 
+— 
+Total operating revenues 
+$ 
+110,733 
+$ 
+127,644 
+$ 
+89,882 
+$ 
+142,145 
+$ 
+141,312 
+Operating expenses: 
+Non-impairment related operating expenses 
+$ 
+100,043 
+$ 
+88,022 
+$ 
+68,703 
+$ 
+68,692 
+$ 
+97,497 
+Impairment of oil and gas properties (b) 
+— 
+— 
+— 
+— 
+485,498 
+Total operating expenses 
+$ 
+100,043 
+$ 
+88,022 
+$ 
+68,703 
+$ 
+68,692 
+$ 
+582,995 
+Income (loss) from continuing operations 
+10,690 
+39,622 
+21,179 
+73,453 
+(441,683 
+) 
+Net income (loss) (c) 
+2,747 
+106,396 
+8,386 
+46,796 
+(438,893 
+) 
+Earnings (loss) per share ("EPS"): 
+Basic 
+$ 
+0.07 
+$ 
+2.81 
+$ 
+0.29 
+$ 
+2.12 
+$ 
+(20.68 
+) 
+Diluted 
+$ 
+0.07 
+$ 
+2.76 
+$ 
+0.28 
+$ 
+2.11 
+$ 
+(20.68 
+) 
+Weighted average number of shares outstanding for Basic EPS 
+39,522 
+37,908 
+28,817 
+22,072 
+21,222 
+Weighted average number of shares outstanding for Diluted EPS 
+40,337 
+38,582 
+29,476 
+22,200 
+21,222 
+Statement of Cash Flows Data: 
+Net cash provided by operating activities 
+$ 
+51,290 
+$ 
+79,167 
+$ 
+100,102 
+$ 
+19,698 
+$ 
+89,054 
+Net cash used in investing activities 
+(93,703 
+) 
+(91,511 
+) 
+(59,738 
+) 
+(43,189 
+) 
+(4,511 
+) 
+Net cash provided by (used in) financing activities 
+(243 
+) 
+38,703 
+(26,252 
+) 
+10,000 
+(120,667 
+) 
+Balance Sheet Data: 
+Oil and natural gas properties, net 
+$ 
+269,521 
+$ 
+215,912 
+$ 
+168,868 
+$ 
+130,608 
+$ 
+159,252 
+Total assets 
+378,173 
+369,707 
+218,326 
+227,991 
+266,090 
+Long-term debt (d) 
+120,668 
+125,345 
+165,504 
+179,174 
+272,855 
+Stockholder' equity (deficit) 
+205,971 
+201,202 
+15,810 
+(80,854 
+) 
+(129,804 
+) 
+Proved Reserves Data: 
+Total oil (MMBbls) 
+10,780 
+10,075 
+8,149 
+6,479 
+6,027 
+Total natural gas (MMcf) 
+19,753 
+35,118 
+32,957 
+19,103 
+18,652 
+Total proved reserves (MBoe) 
+14,072 
+15,928 
+13,641 
+9,663 
+9,136 
+Standardized measure 
+$ 
+231,148 
+$ 
+270,357 
+$ 
+198,916 
+$ 
+135,921 
+$ 
+86,305 
+(a) 
+Following the decisions resulting from several court cases brought by another oil and gas company, the court ruled that the BOEM was not entitled to receive these royalty payments. The amount above reflects royalty recoupments for production from the fields 2003 inception through December 31, 2008, which were accrued at December 31, 2009 and paid by the BOEM during 2010. 
+(b) 
+In 2008, the Company recorded a $485.5 million impairment of oil and gas properties as a result of the ceiling test. See Notes 2 and 12 to the Consolidated Financial Statements for a description of the relevant accounting policy and the Company’s oil and gas properties disclosures, respectively. 
+(c) 
+Net income for 2011 includes $69.3 million of income tax benefit related to the reversal of the Company's deferred tax asset valuation allowance. See Note 11 for additional information. 
+(d) 
+2012 and 2011 long-term debt includes a non-cash deferred credit of $13,707 and $18,384 , respectively that will be amortized into earnings as a reduction to interest expense over the life of the 13% Senior Notes due 2016. See Note 5 for additional information. 
+34 
+Table of Contents 
+ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 
+General 
+The following management's discussion and analysis is intended to assist in understanding the principal factors affecting the Company's results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing. 
+We have been engaged in the exploration, development, acquisition and production of oil and gas properties since 1950. In 2009, we began to shift our operational focus from exploration in the Gulf of Mexico to building an onshore asset portfolio in order to provide a multi-year, low-risk drilling program in both oil and natural gas basins. This onshore transition has been, and is expected to continue to be, primarily funded by reinvesting the cash flows from our Gulf of Mexico properties including, as previously discussed, the proceeds from the monetization of our interest in the deepwater Habanero field in the fourth quarter of 2012. 
+Well count information is presented gross unless otherwise indicated. 
+Overview and Outlook 
+During 2012 , Callon realized net income and fully diluted earnings per share of $2.7 million and $0.07 , respectively, compared to net income of $106.4 million and fully diluted earnings per share of $2.76 , respectively for 2011 . Net income during 2011 benefited significantly from an income tax benefit of $69.3 million , that related primarily to the full reversal of a valuation allowance we previously recorded against our deferred tax assets (see Note 11 for additional information). The Company’s earnings, and the drivers of these earnings, are discussed in greater detail within the “Results of Operations” section included below. 
+During 2012 , the Company continued to transition its asset base from primarily offshore to primarily onshore, seeking to replace high volume offshore production with long-lived onshore crude oil production. In addition to building upon its portfolio of unconventional drilling opportunities with a crude oil focus, the Company continued to expand upon its expertise as an onshore operator in the Permian basin while maintaining a strong financial position to facilitate future growth. Significant accomplishments for 2012 include: 
+• 
+Increased 2012 Permian basin production by 67% to 591 Mboe as compared to 2011 , 
+• 
+Increased 2012 Permian basin proved reserves by 24% to 9.4 MMboe as compared to 2011 , 
+• 
+Increased 2012 Permian basin leasehold position by 246% to 32,962 net acres as compared to 2011 , 
+• 
+Commenced the horizontal development of our East Bloxom field in the southern portion of the Midland basin, with the drilling of two horizontal wells targeting the Wolfcamp B shale. The average initial (24-hour) production rate from these two wells was 801 Boe per day, with an oil composition of 83%, 
+• 
+Commenced the evaluation of our newly acquired northern Midland acreage position, testing numerous vertical and horizontal development concepts, 
+• 
+Accelerated offshore cash flows for onshore redeployment with the sale of our interest in the Habanero field for $39.4 million , and 
+• 
+Expanded our lending bank group to five institutions and increased our Credit Facility size by $20.0 million or 44% as compared to December 31, 2011. 
+35 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+Table of Contents 
+Highlights of our onshore activity and Gulf of Mexico operations include: 
+Onshore - Permian Basin 
+We expect that our production and reserve growth initiatives will continue to focus primarily on the Permian basin, in which we own approximately 38,127 gross ( 32,962 net) acres as of December 31, 2012 . 
+Southern Portion: We currently own approximately 11,345 net acres in the southern portion of the Permian basin, an increase of 19% since year-end 2011. Our current production in the southern Midland basin (Crockett, Ector, Glasscock, Midland, and Upton counties in Texas) is primarily from the Wolfberry play, although we added production volumes from the horizontal development of the Wolfcamp B shale during 2012. 
+During 2012, we drilled 15 vertical wells and completed 22 vertical wells. As part of this program, we tested deeper target zones below the Atoka in the fourth quarter of 2012. Based on the results of this test, we are currently planning to add these deeper zones to our ongoing vertical Wolfberry-type drilling and completion program at our Pecan Acres and Carpe Diem fields. 
+In addition to this vertical drilling program, we commenced a horizontal oil shale drilling program at our East Bloxom field in the second quarter of 2012, initially targeting the Wolfcamp B formation. In 2012, we drilled and completed two horizontal wells on this acreage position, each with a lateral length of over 7,100 feet. In the first quarter of 2013, we drilled an additional three horizontal Wolfcamp shale wells at East Bloxom, with two wells targeting the Wolfcamp B shale and one targeting the Wolfcamp A shale. 
+In order to increase our exposure to horizontal development of the Wolfcamp B shale, we acquired 2,319 gross ( 1,762 net) acres in southern Reagan county, Texas, which closed on July 5, 2012, and is now referred to as our Taylor Draw field. We finished the drilling of our initial horizontal well, targeting the Wolfcamp B shale, in December 2012, completed the well in February 2013, and are currently evaluating the well results that include some positive indications. 
+Based on our initial results and the results of other industry participants, we are planning to increase our level of horizontal drilling activity in 2013 in this portion of the basin, drilling a total of 14 wells. Given this level of sustained activity, we are planning on executing these wells from drilling pads using batch completions in an effort to maximize capital efficiency. These development plans are currently expected to be focused on our East Bloxom and Taylor Draw fields. 
+Northern Portion: We currently own approximately 21,617 net acres in the northern portion of the Permian basin, which includes the 14,653 net acres in Borden county, Texas and an additional 6,964 net acres in Lynn county, Texas. These leasehold positions were acquired during the course of 2012 for a total consideration of $19.4 million , or $896 per net acre. These positions represent our effort to expand our drilling inventory in the Midland basin with exploration upside potential at a reasonable cost of entry. 
+After completing a 3-D seismic survey on our acreage position, we commenced the drilling of an exploratory vertical well in July 2012, followed by the drilling of two horizontal wells. The first horizontal well was drilled in the Cline shale and was completed in December 2012. The hydrocarbons from this well did not produce in economic quantities and the well was temporarily abandoned in February 2013. We drilled the second horizontal well, targeting the Mississippian lime interval, in November 2012, completed the well in February 2013 and are currently evaluating the well results. 
+Although the area has experienced a recent increase in drilling activity, the northern Midland basin has had limited drilling activity compared with the southern basin (where our current production is located), which significantly increases the risk associated with successful drilling activities in this area. 
+In addition to the $29.6 million consideration paid for each of the above referenced leasehold additions, the Company's unevaluated property balance of $68.8 million at December 31, 2012 includes $29.7 million of exploration and facility costs incurred in 2012 on these properties and $9.5 million of other related items. See Note 12 for additional information. Based on the Company's present development plans, the Company expects the majority of the exploration and facility costs will be transferred to evaluated properties during 2013. 
+36 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+Table of Contents 
+Offshore - Deepwater 
+Our net interest in the Habanero field produced an average of 366 Boe per day for 2012 . The field was shut-in for approximately 50 days during the year for scheduled maintenance, and hurricane-related issues. On December 28, 2012, we completed the sale of our interest in the Habanero field to Shell Offshore Inc., a subsidiary of Royal Dutch Shell Plc, for net cash consideration of $ 39.4 million. 
+Our remaining deepwater property, our 15% interest in the Medusa field, continues to play a key role in our portfolio. Our net interest in the Medusa field produced an average of 1,268 Boe per day during 2012 , approximately 87% being crude oil that receives pricing based on Mars WTI crude. The Medusa platform was shut-in for 28 days during the second quarter of 2012 for planned construction activities on the West Delta 143 oil pipeline through which Medusa's production is transported. Due to Hurricane Isaac, the platform was once again shut-in from August 27, 2012 to September 4, 2012. 
+We anticipate that the future cash flows from Medusa will continue to contribute to the funding of our onshore activity. In addition, we believe that additional reserve potential exists as part of this project. The operator of the field, Murphy Oil Corporation, has sanctioned a two well subsea development for the Medusa field. One of these wells will be targeting the development of reserves associated with our existing PUD reserves in the T-4B sand with an uphole recomplete to the T-0A and T-0B sand. The remaining well will target probable reserves. We anticipate that the drilling of these wells will begin in the first quarter of 2014. 
+Offshore – Shelf & Other Properties 
+We own interests in 14 producing wells in eight crude oil and natural gas fields in the shelf area of the Gulf of Mexico. These wells produced 340 MBoe net to our interest in 2012 , which accounted for 22% of our total production. Production from the East Cameron Block 257 field, which contributed an average of 175 Boe per day of production prior to being shut-in in November 2011, is expected to recommence once the Stingray Pipeline is brought back online. The restart of flows on the pipeline is currently anticipated to occur in the second quarter of 2013. 
+Liquidity and Capital Resources 
+Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities. Cash and cash equivalents decreased by $42.7 million during 2012 to $1.1 million compared to $43.8 million at December 31, 2011 . The decrease in our cash balance is primarily attributable to 2012 capital expenditures of $133.3 million , representing a $33.1 million or 33% increase over the amount spent during the same period in 2011 . While at December 31, 2012, our Balance Sheet reflects a working capital deficiency of $18.6 million , which is reflective of our current capital investment-driven growth strategy within our Permian properties, we believe that as discussed below our operating cash flows combined with the borrowing availability under our Credit Facility provides the liquidity necessary to meet our operational cashflow needs. 
+Senior Secured Credit Facility (the "Credit Facility") 
+On June 20, 2012, Regions Bank increased the Company's Credit Facility to $200 million with an associated borrowing base under the Credit Facility of $60 million and a maturity of July 31, 2014. Subsequently and in October 2012, the Credit Facility was further amended to increase the borrowing base to $80 million, extend the maturity to March 15, 2016 and add Citibank, NA, IberiaBank, Whitney Bank and OneWest Bank, FSB as participating lenders. Regions Bank continues to serve as Administrative Agent for the Credit Facility. 
+As of December 31, 2012 the borrowing base was revised to $65 million following the sale of our interest in the deepwater Habanero field. Proceeds from the sale, net cash consideration of $39.4 million after customary purchase price adjustments, were used to reduce outstanding borrowings on our Credit Facility. The borrowing base will be redetermined as scheduled in the first quarter of 2013 based upon the evaluation of year-end proved reserves. 
+Amounts borrowed under the Credit Facility may not exceed a borrowing base, which is generally reviewed on a semi-annual basis and is then eligible for re-determination. The Credit Facility is secured by mortgages covering the Company's major producing fields. 
+As of December 31, 2012 , the balance outstanding under the Credit Facility was $10.0 million with a weighted average interest rate on the Credit Facility of 2.72% , calculated as the London Interbank Offered Rate (“LIBOR”) plus a tiered rate ranging from 2.5% to 3.0% , which is based on utilization of the Credit Facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum on the unused portion of the borrowing base, which is payable quarterly. As of March 13, 2013 , the balance outstanding 
+37 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+Table of Contents 
+on the Credit Facility was $25 million as the Company drew an additional $15 million in support of the Company's ongoing capital development program. 
+Senior Notes due 2016 
+At December 31, 2012 , following a $10 million principal redemption in June 2012, we had approximately $97 million principal amount of 13% Senior Notes due 2016 outstanding with interest payable quarterly. 
+2013 Capital Expenditures 
+For 2013 , we designed a flexible capital spending program, which we plan to fund from cash on hand and cash flows from operations in addition to borrowings under our Credit Facility. However, depending on macroeconomic conditions or the Company's operational results, our capital budget may be adjusted up or down during the year. 
+Our 2013 capital budget has been established at $125.0 million with over 90% of our budgeted operating expenditures (including drilling, completion, infrastructure, and plugging and abandonment) allocated to our Midland basin operations.. The 15% decrease in total capital from 2011 reflects our primary focus on drilling and completion activities in the Permian basin and reduced emphasis on acreage acquisitions that were budgeted in 2012 to expand the Company's presence in the basin. Our budget includes further exploration and development of our Permian basin properties with plans to complete approximately 26 gross wells including 14 horizontal wells and 12 vertical wells. Components of the 2013 capital budget include (in millions): 
+Midland basin 
+$ 
+97 
+Gulf of Mexico 
+10 
+Total projected operations budget 
+107 
+Capitalized general and administrative costs 
+14 
+Capitalized interest and other 
+4 
+Total projected capital expenditures budget 
+$ 
+125 
+Our total liquidity at December 31, 2012 was $56.1 million , including $1.1 million of cash available and $55.0 million of availability under our Credit Facility. We believe that this liquidity position, combined with our expected operating cash flow based on current commodity prices and forecasted production, will be adequate to meet our forecasted capital expenditures, interest payments, and operating requirements for 2013 . 
+38 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+Table of Contents 
+The following table includes the Company’s contractual obligations and purchase commitments as of December 31, 2012 , at which date the Company had no product delivery commitments: 
+(amounts in thousands) 
+Payments due by Period 
+Total 
+< 1 Year 
+Years 2 - 3 
+Years 4 - 5 
+>5 Years 
+13% Senior Notes 
+$ 
+96,961 
+$ 
+— 
+$ 
+— 
+$ 
+96,961 
+$ 
+— 
+Office space lease commitments 
+3,012 
+384 
+785 
+719 
+1,124 
+Drilling rig leases and related (a) 
+11,512 
+9,235 
+2,277 
+— 
+— 
+Other 
+40 
+13 
+27 
+— 
+— 
+Total 
+$ 
+111,525 
+$ 
+9,632 
+$ 
+3,089 
+$ 
+97,680 
+$ 
+1,124 
+(a) 
+The agreement includes early termination provisions that would reduce the minimum rentals under the agreement, assuming the lessor is unable to re-charter the rig and staffing personnel to another lessee, as follows: <1 year of $5.8 million and 2-3 years of $1.4 million . 
+Summary cash flow information is provided as follows: 
+Operating Activities. For the year ended December 31, 2012 , net cash provided by operating activities was $51.3 million , compared to $79.2 million for the same period in 2011 . The decrease relates primarily to lower revenues from a 2% decrease in crude oil production, a 29% decrease in natural gas production and a 31% increase in lease operating expenses, partially offset by a 2% increase in the average sales price on an equivalent basis. Production and realized prices are discussed below in Results of Operations. 
+Investing Activities. For the year ended December 31, 2012 , net cash used in investing activities was $93.7 million as compared to $91.5 million for the same period in 2011 . The net $2.2 million increase in ca sh used in investing activities is primarily attributable to a $33.1 million increase in capital expenditures related to development activity on our Permian basin acreage and $2.1 million for producing property acquisitions. These expenditures were largely offset by a $32.3 million year-over-year increase in proceeds received for the sale of certain mineral interests including the late 2012 sale of our interest in the deepwater Habanero field discussed below and in Note 12 to the financial statements. The $33.1 million increase in capital expenditures includes the acquisition of additional acreage in Borden and Lynn counties located in the northern Midland basin, additional acreage in Reagan county in the southern Midland basin and costs associated with the horizontal drilling activity. 
+Financing Activities . For the year ended December 31, 2012 , net cash used in financing activities was $0.2 million compared to cash provided by financing activities of $38.7 million during the same period of 2011 . Net cash used for 2012 financing activities included a net $10 million draw on our Credit Facility offset by the $10.2 million redemption of Senior Notes. Net cash provided by 2011 financing activities included $73.8 million of net proceeds from an equity offering offset by approximately $35.1 million used to redeem a $31 million principal portion of our outstanding 13% Senior Notes and to pay the $4.0 million call premium and other redemption expenses. 
+Income Taxes 
+Prior to 2012, we carried a full valuation allowance against our net deferred tax asset. The income tax benefit of $69.3 million in 2011 resulted primarily from the reversal of the valuation allowance established in 2008 against our net deferred tax assets. As a result of reporting net income from 2009 to 2011, we achieved income on an aggregate basis for the three-year period ended December 31, 2011. Additionally we expect to generate sufficient taxable income necessary to fully utilize all of the deferred tax assets prior to their expiration. Consequently, we reversed the $69.3 million valuation allowance at December 31, 2011. For additional information, see Note 11 to the Consolidated Financial Statements. 
+Global Settlement with Joint Interest Partner 
+During the second quarter of 2011, we entered into a final project wind-down agreement with a former joint interest partner in a deepwater project. The agreement provided for the extinguishment of all existing agreements and commitments between the parties as it relates to the past development of the deepwater project. The agreement also included a formal extinguishment of the non-recourse credit agreement between the parties and the assignment to us of the joint interest partner's 50% rights to the remaining project assets, which included primarily the unsold, residual equipment and all engineering data. For additional information regarding the settlement, please refer to Note 3 included in Item II, Part 8 of this filing. 
+39 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+Table of Contents 
+Results of Operations 
+The following table sets forth certain unaudited operating information with respect to the Company's oil and natural gas operations for the periods indicated: 
+For the year ended December 31, 
+2012 
+2011 
+Change 
+% Change 
+2010 
+Change 
+% Change 
+Net production: 
+Crude oil (MBbls) 
+977 
+996 
+(19 
+) 
+(2 
+)% 
+859 
+137 
+16 
+% 
+Natural gas (MMcf) 
+3,588 
+5,081 
+(1,493 
+) 
+(29 
+)% 
+4,892 
+189 
+4 
+% 
+Total production (MBoe) 
+1,575 
+1,843 
+(268 
+) 
+(15 
+)% 
+1,674 
+169 
+10 
+% 
+Average daily production (Boe) 
+4,303 
+5,049 
+(746 
+) 
+(15 
+)% 
+4,587 
+462 
+10 
+% 
+Average realized sales price (see below): 
+Crude oil (Bbl) 
+$ 
+98.86 
+$ 
+101.34 
+$ 
+(2.48 
+) 
+(2 
+)% 
+$ 
+75.97 
+$ 
+25.37 
+33 
+% 
+Natural gas (Mcf) 
+3.94 
+5.25 
+(1.31 
+) 
+(25 
+)% 
+5.04 
+0.21 
+4 
+% 
+Total (Boe) 
+70.31 
+69.26 
+1.05 
+2 
+% 
+53.69 
+15.57 
+29 
+% 
+Crude oil and natural gas revenues (in thousands): 
+Crude oil revenue 
+$ 
+96,584 
+$ 
+100,962 
+$ 
+(4,378 
+) 
+(4 
+)% 
+$ 
+65,243 
+$ 
+35,719 
+55 
+% 
+Natural gas revenue 
+14,149 
+26,682 
+(12,533 
+) 
+(47 
+)% 
+24,639 
+2,043 
+8 
+% 
+Total 
+$ 
+110,733 
+$ 
+127,644 
+$ 
+(16,911 
+) 
+(13 
+)% 
+$ 
+89,882 
+$ 
+37,762 
+42 
+% 
+Additional per Boe data: 
+Sales price 
+$ 
+70.31 
+$ 
+69.26 
+$ 
+1.05 
+2 
+% 
+$ 
+53.69 
+$ 
+15.57 
+29 
+% 
+Lease operating expense 
+(16.86 
+) 
+(11.04 
+) 
+(5.82 
+) 
+(53 
+)% 
+(10.58 
+) 
+(0.46 
+) 
+4 
+% 
+Operating margin 
+$ 
+53.45 
+$ 
+58.22 
+$ 
+(4.77 
+) 
+(8 
+)% 
+$ 
+43.11 
+$ 
+15.11 
+35 
+% 
+Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil and Mcf of natural gas: 
+Average NYMEX oil price ($/Bbl) 
+$ 
+94.19 
+$ 
+95.14 
+$ 
+(0.95 
+) 
+(1 
+)% 
+$ 
+79.52 
+$ 
+15.62 
+20 
+% 
+Basis differential and quality adjustments (a) 
+3.97 
+7.58 
+(3.61 
+) 
+(48 
+)% 
+(2.39 
+) 
+9.97 
+(417 
+)% 
+Transportation 
+(0.75 
+) 
+(1.00 
+) 
+0.25 
+25 
+% 
+(1.16 
+) 
+0.16 
+(14 
+)% 
+Hedging (b) 
+1.45 
+(0.38 
+) 
+1.83 
+482 
+% 
+— 
+(0.38 
+) 
+100 
+% 
+Average realized oil price ($/Bbl) 
+$ 
+98.86 
+$ 
+101.34 
+$ 
+(2.48 
+) 
+(2 
+)% 
+$ 
+75.97 
+$ 
+25.37 
+33 
+% 
+Average NYMEX natural gas price ($/Mcf) 
+$ 
+2.82 
+$ 
+4.03 
+$ 
+(1.21 
+) 
+(30 
+)% 
+$ 
+4.40 
+$ 
+(0.37 
+) 
+(8 
+)% 
+Basis differential and quality adjustments (c) 
+1.12 
+1.22 
+(0.10 
+) 
+(8 
+)% 
+0.51 
+0.71 
+139 
+% 
+Hedging (b) 
+— 
+— 
+— 
+n/a 
+0.13 
+(0.13 
+) 
+(100 
+)% 
+Average realized natural gas price ($/Mcf) 
+$ 
+3.94 
+$ 
+5.25 
+$ 
+(1.31 
+) 
+(25 
+)% 
+$ 
+5.04 
+$ 
+0.21 
+4 
+% 
+(a) 
+Crude oil prices for production from our two deepwater fields include a premium over NYMEX pricing based on Mars WTI differential for Medusa production and Argus Bonita WTI differential for Habanero production. 
+(b) 
+As discussed in Note 6 , the Company discontinued hedge accounting beginning with derivative contracts executed on January 1, 2012. Consequently, the realized portion of derivative contracts is now included in the statement of operations within Gain on derivative contracts. The amounts reported above reflect the realized portion of derivative contracts designated as cash flow hedges. 
+(c) 
+Natural gas prices exceeded the related NYMEX prices, which are quoted on an MMBtu basis, primarily due to the value of the NGLs in our liquids-rich natural gas stream, primarily from our Permian basin and deepwater production. 
+40 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+Table of Contents 
+Revenues 
+The following tables are intended to reconcile the change in oil, natural gas and total revenue by reflecting the effect of changes in volume, changes in the underlying commodity prices and the impact of our hedge program (in thousands): 
+Oil 
+Natural Gas 
+Total 
+Revenues for the year ended December 31, 2009 
+$ 
+73,842 
+$ 
+27,417 
+$ 
+101,259 
+Volume decrease 
+(11,164 
+) 
+(4,050 
+) 
+(15,214 
+) 
+Price increase 
+2,556 
+649 
+3,205 
+Impact of hedges increase 
+9 
+623 
+632 
+Net decrease during the year 
+(8,599 
+) 
+(2,778 
+) 
+(11,377 
+) 
+Revenues for the year ended December 31, 2010 
+$ 
+65,243 
+$ 
+24,639 
+$ 
+89,882 
+Volume increase 
+10,406 
+952 
+11,358 
+Price increase 
+25,688 
+1,091 
+26,779 
+Impact of hedges decrease 
+(375 
+) 
+— 
+(375 
+) 
+Net increase during the year 
+35,719 
+2,043 
+37,762 
+Revenues for the year ended December 31, 2011 
+$ 
+100,962 
+$ 
+26,682 
+$ 
+127,644 
+Volume decrease 
+(1,926 
+) 
+(7,840 
+) 
+(9,766 
+) 
+Price decrease 
+(3,872 
+) 
+(4,693 
+) 
+(8,565 
+) 
+Impact of hedges increase 
+1,420 
+— 
+1,420 
+Net decrease during the year 
+(4,378 
+) 
+(12,533 
+) 
+(16,911 
+) 
+Revenues for the year ended December 31, 2012 
+$ 
+96,584 
+$ 
+14,149 
+$ 
+110,733 
+Crude Oil Revenue 
+For the year ended December 31, 2012 , crude oil revenues of $96.6 million decreased $4.4 million or 4% compared to revenues of $101.0 million for the year ended December 31, 2011 . A decrease in commodity prices and production resulted in decreased oil revenue. The average price realized decreased 2% to $98.86 per barrel compared to $101.34 for the same period of 2011. Similarly, production decreased by 2% to 977 MBbls compared to 996 MBbls during the same period in 2011. Crude oil prices for production from our two deepwater fields are adjusted and reflect a premium over NYMEX pricing based on Mars WTI differential for Medusa production and Bonita WTI differential for Habanero production. Production decreases relate primarily to the down-time at the Habanero and Medusa fields and the normal and expected declines from our other offshore properties. These production declines were offset by production from our new Permian wells, 22 vertical and two horizontal, brought onto production during 2012. 
+For the year ended December 31, 2011, crude oil revenues of $101.0 million increased $35.7 million or 55% compared to revenues of $65.2 million for the year ended December 31, 2010. An increase in commodity prices and production resulted in increased crude oil revenue. The average price realized increased 33% to $101.34 per barrel compared to $75.97 for the same period of 2010. Similarly, production increased by 16% to 996 MBbls compared to 859 MBbls during the same period in 2010. Crude oil prices for production from our two deepwater fields are adjusted and reflect a premium over NYMEX pricing based on Mars WTI differential for Medusa production and Bonita WTI differential for Habanero production. Production increases relate primarily to progress in developing our Permian basin properties and a successful recompletion at our Medusa field, partially offset by the downtime experienced at our deepwater fields and due to normal and expected declines in our other properties. 
+41 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+Table of Contents 
+Natural Gas Revenue 
+For the year ended December 31, 2012 , natural gas revenues of $14.1 million represented a decrease of 47% or $12.5 million when compared to natural gas revenues of $26.7 million for the year ended December 31, 2011 . Natural gas production decreased 29% , driven primarily by down time at our Haynesville well, which was shut-in for 70 days during the first quarter of 2012 due to well interference from an offsetting well, and due to down time at our East Cameron 257 well, which was suspended in the fourth quarter of 2011 due to a natural gas leak in an upstream section of the Stingray Pipeline that transports production volumes from the field. Production from our East Cameron 257 well is expected to resume once the pipeline is brought back online during the second quarter of 2013. Also contributing to the decline was the previously discussed down-time at our Habanero and Medusa fields and normal and expected declines in natural gas production from our offshore and Haynesville wells. In addition to production decreases , the average realized price decreased 25% to $3.94 per Mcf compared to an average realized price of $5.25 per Mcf in 2011 . Our natural gas prices on an MMBtu equivalent basis exceeded the related NYMEX prices primarily due to the value of the NGLs in our natural gas stream, primarily from our Permian basin and deepwater production. 
+For the year ended December 31, 2011, natural gas revenues of $26.7 million represented an increase of 8% or $2.0 million when compared to natural gas revenues of $24.6 million for the year ended December 31, 2010. Natural gas production increased 4%, primarily driven by production from our Haynesville Shale natural gas well, which was placed on production during September 2010, and due to down time at our East Cameron #2 field, which was shut-in during the first quarter of 2010 for repairs to the host facility and did not return to production until December 2010. In addition to production increases, the average realized price increased 4% to $5.25 per Mcf compared to an average realized price of $5.04 per Mcf in 2010. Our natural gas prices on an MMBtu equivalent basis exceeded the related NYMEX prices primarily due to the value of the NGLs in our natural gas stream, primarily from our Permian basin and deepwater production. Offsetting the increases in production are normal and expected declines in production from our other natural gas properties and a 35-day shut-in, as of December 31, 2011, of our Haynesville well due to interference caused by an offsetting well. The Haynesville well returned to production in mid-March 2012. 
+42 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+Table of Contents 
+Operating Expenses 
+For the year ended December 31, 
+Total Change 
+Boe Change 
+2012 
+Per Boe 
+2011 
+Per Boe 
+$ 
+% 
+$ 
+% 
+Lease operating expenses 
+$ 
+26,554 
+$ 
+16.86 
+$ 
+20,347 
+$ 
+11.04 
+$ 
+6,207 
+31 
+% 
+$ 
+5.82 
+53 
+% 
+Depreciation, depletion and amortization 
+49,701 
+31.56 
+48,701 
+26.42 
+1,000 
+2 
+% 
+5.14 
+19 
+% 
+General and administrative 
+20,358 
+12.93 
+16,636 
+9.03 
+3,722 
+22 
+% 
+3.9 
+43 
+% 
+Accretion expense 
+2,253 
+1.43 
+2,338 
+1.27 
+(85 
+) 
+(4 
+)% 
+0.16 
+13 
+% 
+Impairment of other property and equipment (See Note 3) 
+1,177 
+0.75 
+— 
+— 
+1,177 
+100 
+% 
+0.75 
+100 
+% 
+Total operating expenses 
+$ 
+100,043 
+$ 
+88,022 
+For the year ended December 31, 
+Total Change 
+Boe Change 
+2011 
+Per Boe 
+2010 
+Per Boe 
+$ 
+% 
+$ 
+% 
+Lease operating expenses 
+$ 
+20,347 
+$ 
+11.04 
+$ 
+17,712 
+$ 
+10.58 
+2,635 
+15 
+% 
+$ 
+0.46 
+4 
+% 
+Depreciation, depletion and amortization 
+48,701 
+26.42 
+31,805 
+19.00 
+16,896 
+53 
+% 
+7.42 
+39 
+% 
+General and administrative 
+16,636 
+9.03 
+16,507 
+9.86 
+129 
+1 
+% 
+(0.83 
+) 
+(8 
+)% 
+Accretion expense 
+2,338 
+1.27 
+2,446 
+1.46 
+(108 
+) 
+(4 
+)% 
+(0.19 
+) 
+(13 
+)% 
+Acquisition expense 
+— 
+— 
+233 
+0.14 
+(233 
+) 
+(100 
+)% 
+(0.14 
+) 
+(100 
+)% 
+Total operating expenses 
+$ 
+88,022 
+$ 
+68,703 
+Lease Operating Expenses 
+For the year ended December 31, 2012 , lease operating expenses ("LOE") of $26.6 million increased 31% or $6.2 million compared to $20.3 million for the year ended December 31, 2011 . The increase was primarily due to $4.2 million in costs related to significant growth in the number of wells now producing in our Permian basin properties and $3.3 million associated with the remediation work on the Haynesville well. These increases were partially offset by a $1.3 million decline in LOE for our deepwater properties due to lower throughput charges as a result of reduced production volumes discussed previously. 
+For the year ended December 31, 2011, lease operating expenses ("LOE") of $20.3 million increased by 15% or $2.6 million compared to $17.7 million for the year ended December 31, 2010. The significant growth in the number of wells now producing in our Permian basin properties and our Haynesville Shale well increased total LOE approximately $3.6 million , or $1.95 on a per Boe basis, compared to the corresponding period of 2010. Additionally, total LOE increased approximately $0.5 million related to Medusa Spar maintenance work, the increased production from the Medusa A6 well following the well recompletion, and increased $0.8 million due to processing fees at our East Cameron #2 well, which resumed production in December 2010 after being shut-in for repairs on the host facility during the first quarter of 2010. Partially offsetting these increases was a mix of lower LOE related primarily to our shelf properties. 
+Depreciation, Depletion and Amortization 
+Depreciation, depletion and amortization (“DD&A”) for the year ended December 31, 2012 increased 19% per Boe to $31.56 per Boe compared to $26.42 per Boe for the year ended December 31, 2011 . The prior period DD&A rates were effectively reduced by the impact of a $486 million 2008 impairment charge following a ceiling test writedown. This significant oil and natural gas property impairment charge resulted in a lower, prospective DD&A rate for the then existing reserves. Increases in the DD&A rate subsequent to that impairment are attributable to our planned exploration and development expenditures related to our onshore reserve development including the ongoing onshore development cost increases in the Permian basin area. We currently estimate that a normalized DD&A rate for our properties will approximate $36.00 per Boe. 
+43 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+Table of Contents 
+Depreciation, depletion and amortization (“DD&A”) for the year ended December 31, 2011 increased 39% per Boe to $26.42 per Boe compared to $19.00 per Boe for the year ended December 31, 2010. Onshore development cost increases account for nearly all of the increase. 
+General and Administrative, net of amounts capitalized 
+For the year ended December 31, 2012 , general and administrative (“G&A”) expenses, net of amounts capitalized, increased $3.7 million or 22% to $20.4 million from $16.6 million for the same period of 2011 . The increase is due mainly to $1.6 million in costs for non-recurring employee-related expenses including early retirement and severance expense for which we had no expense during the same period of 2011. Additionally, we incurred an increase in non-cash charges of $1.2 million related to incentive compensation share-based instruments awarded during 2012. The remaining increase relates primarily to higher compensation-related expenses including the costs associated with employing staff to support our onshore growth and 100% operated Permian production, as well as relocation and related costs. 
+For the year ended December 31, 2011, G&A expenses of $16.6 million, net of amounts capitalized, was relatively flat compared to $16.5 million for the year ended 2010. 
+Accretion Expense 
+Accretion expense related to our asset retirement obligation decreased 4% for the year ended December 31, 2012 compared to the same periods of 2011. Accretion expense correlates directionally with the Company's asset retirement obligation (“ARO”). At December 31, 2012 , our ARO of $13.3 million was lower than the $13.9 million ARO at December 31, 2011 . See Note 13 for additional information regarding the Company's ARO. 
+For the year ended December 31, 2011, accretion expense decreased 4% for the year ended December 31, 2011 compared to the same periods of 2010. The Company's accretion expense decreases as its ARO decreases. At December 31, 2011, our ARO of $13.9 million was lower than the $15.9 million ARO at December 31, 2010. See Note 13 for additional information regarding the Company's ARO. 
+Impairment of Other Property and Equipment 
+During 2012, the Company recorded a write-down of the value of certain assets acquired in 2011 as part of a settlement reached with a former joint interest partner on a deepwater project. For information concerning the impairment of these assets, which are currently classified as available for sale, please see Note 3 to the Consolidated Financial Statements. 
+44 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+Table of Contents 
+Other (Income) Expense 
+For the year ended December 31, 
+2012 
+2011 
+$ Change 
+% Change 
+2010 
+$ Change 
+% Change 
+Interest expense 
+$ 
+9,108 
+$ 
+11,717 
+$ 
+(2,609 
+) 
+(22 
+)% 
+$ 
+13,312 
+$ 
+(1,595 
+) 
+(12 
+)% 
+(Gain) loss on early extinguishment of debt 
+(1,366 
+) 
+(1,942 
+) 
+576 
+30 
+% 
+339 
+(2,281 
+) 
+(673 
+)% 
+Gain on acquired assets (See Note 3) 
+— 
+(5,041 
+) 
+5,041 
+100 
+% 
+— 
+(5,041 
+) 
+(100 
+)% 
+Gain on derivative contracts 
+(1,717 
+) 
+— 
+(1,717 
+) 
+(100 
+)% 
+— 
+— 
+— 
+% 
+Other (income) expense 
+(79 
+) 
+(1,426 
+) 
+1,347 
+94 
+% 
+(257 
+) 
+(1,169 
+) 
+(455 
+)% 
+Total other expenses,net 
+$ 
+5,946 
+$ 
+3,308 
+$ 
+13,394 
+Income tax expense (benefit) 
+$ 
+2,223 
+$ 
+(69,283 
+) 
+$ 
+71,506 
+103 
+% 
+$ 
+(174 
+) 
+$ 
+(69,109 
+) 
+(39,718 
+)% 
+Equity in earnings of Medusa Spar LLC 
+226 
+799 
+(573 
+) 
+(72 
+)% 
+427 
+372 
+87 
+% 
+Interest Expense 
+Interest expense on Callon's debt obligations decreased 22% to $9.1 million for the year ended December 31, 2012 compared to $11.7 million for the same period of 2011 . The decrease relates primarily to the redemption of $10 million principal of 13% Senior Notes during June 2012 in addition to a $1.5 million increase in capitalized interest compared to 2011, partially offset by interest expense related to increased borrowings under our Credit Facility and decreases in the deferred credit amortization. The increase in capitalized interest relates to a higher balance year-over-year in average unevaluated oil and natural gas properties following the purchase of additional unevaluated acreage with exploration costs in the Permian basin. 
+Interest expense on Callon's debt obligations decreased 12% to $11.7 million for the year ended December 31, 2011 compared to $13.3 million for the same period of 2010. The decrease relates primarily to the redemption of $31 million principal of 13% Senior Notes during March 2011. This early redemption reduced interest expense by approximately $3.2 million for the current year compared to 2010. Additionally, 2010 interest expense included approximately $0.5 million related to the remaining outstanding $16.1 million of 9.75% Senior Notes, which were redeemed on April 30, 2010 and were therefore not included in 2011 interest expense. Offsetting these declines in interest expense is a $1.4 million drop in capitalized interest in 2011 compared to 2010, and relates to a lower balance year-over-year in average unevaluated oil and natural gas properties following the transfer to evaluated earlier in 2011 of certain leases, primarily offshore, that the Company elected not to renew. Further offsetting the declines discussed above are slight decreases in the deferred credit amortization recorded in 2011 compared to 2010. 
+(Gain) Loss on Early Extinguishment of Debt 
+During June 2012, the Company redeemed $10 million of its Senior Notes with a carrying value of $11.6 million , including $1.6 million of the Notes’ deferred credit, in exchange for $10.2 million , comprised of the $10 million principal of the Notes and $0.2 million of redemption expenses, which resulted in a $1.4 million net gain on the early extinguishment of debt. 
+During March 2011, using a portion of the proceeds from the Company's February 2011 equity offering, the Company redeemed 13% Senior Notes with a carrying value of $37 million, including $6.0 million of the Notes' deferred credit, in exchange for $35.1 million, comprised of the $31 million principal of the notes, the $4.0 million call premium and miscellaneous redemption expenses, which resulted in a $1.9 million net gain on the early extinguishment of debt. 
+Gain on Acquired Assets 
+During 2011 and related to the 2012 activity mentioned above, we entered into a settlement with a former deepwater joint interest partner, which included the transfer of certain assets and liabilities to Callon with estimated net fair values of $8.7 million. The assets acquired consisted primarily of the surplus project equipment while the liabilities assumed consisted of deferred tax liabilities associated with the basis difference of the equipment. The adjusted fair market value of the net assets acquired was recorded during 2011 as a $5.0 million gain and a $3.7 million adjustment to our full cost pool of oil and gas properties. The gain recognition was required as a result of our acquiring the joint interest partner's former share of the assets, and the full cost pool adjustment was required to reflect our share of the assets held prior to the deconsolidation of a related subsidiary in 2010. See Note 3 for additional information concerning the gain on acquired assets. 
+45 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+Table of Contents 
+Gain on Derivative Contracts 
+As discussed in Note 6 and beginning with derivative contracts executed in 2012 , the Company elected to no longer designate its derivative contracts as accounting hedges. For the year ended December 31, 2012 , unrealized losses and gains on mark-to-market derivative instruments, net were $1.7 million gain , compared to none in 2011 when all derivative contracts were designated as hedges for accounting purposes. See Notes 6 and 7 for disclosures related to derivative instruments including their composition and valuation. 
+Income Tax Expense (Benefit) 
+The income tax expense of $2.2 million in 2012 resulted primarily from pre-tax income earnings of $4.7 million . See Note 11 for a discussion of our effective tax rate. 
+Prior to 2012, we carried a full valuation allowance against our net deferred tax asset. The income tax benefit of $69.3 million in 2011 resulted primarily from the reversal of the valuation allowance established in 2008 against our net deferred tax assets. As a result of reporting net income from 2009 to 2011, we achieved income on an aggregate basis for the three-year period ended December 31, 2011. Additionally we expect to generate sufficient taxable income necessary to fully utilize all of the deferred tax assets prior to their expiration. Consequently, we reversed the $69.3 million valuation allowance at December 31, 2011. For additional information, see Note 11 to the Consolidated Financial Statements. 
+Off-Balance Sheet Arrangements 
+The Company holds a 10% ownership interest in Medusa Spar LLC (“LLC”), which is accounted for under the equity method of accounting for investments. The LLC owns a 75% undivided ownership interest in the deepwater spar production facilities at the Company’s Medusa field in the Gulf of Mexico. The LLC earns a tariff based upon production volume throughput from the Medusa area. Callon is obligated to process through the spar production facilities its share of production from the Medusa field and any future discoveries in the area. The balance of Medusa Spar LLC is owned by Oceaneering International, Inc. and Murphy Oil Corporation. 
+46 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+Table of Contents 
+Summary of Significant Accounting Policies and Critical Accounting Estimates 
+Property and Equipment 
+The Company utilizes the full-cost method of accounting for its oil and natural gas properties whereby all costs incurred in connection with the acquisition, exploration and development of oil and natural gas reserves, including certain overhead costs, are capitalized into the “full-cost pool.” The amounts capitalized into the full-cost pool are depleted (charged against earnings) using the unit-of-production method. The full-cost method of accounting for our proved oil and natural gas properties requires that the Company makes estimates based on its assumptions of future events that could change. These estimates are described below. 
+Depreciation, Depletion and Amortization (DD&A) of Oil and Natural Gas Properties 
+The Company calculates depletion by using the depletable base, equal to the net capitalized costs in our full-cost pool plus estimated future development costs, and the estimated net proved reserve quantities. Capitalized costs added to the full-cost pool include the following: 
+• 
+costs of drilling and equipping productive wells, dry hole costs, acquisition costs of properties with proved reserves, delay rentals and other costs related to exploration and development of our crude oil and natural gas properties; 
+• 
+payroll costs including the related fringe benefits paid to employees directly engaged in the acquisition, exploration and/or development of crude oil and natural gas properties as well as other directly identifiable general and administrative costs associated with such activities. Such capitalized costs do not include any costs related to the production of crude oil and natural gas or general corporate overhead; 
+• 
+costs associated with unevaluated properties, those lacking proved reserves, are excluded from the depletable base. These unevaluated property costs are added to the depletable base at such time as wells are completed on the properties, the properties are sold or the Company determines these costs have been impaired. The Company’s determination that a property has or has not been impaired (which is discussed below) requires assumptions about future events; 
+• 
+estimated costs to dismantle, abandon and restore properties that are capitalized to the full-cost pool when the related liabilities are incurred (see also the discussion below regarding Asset Retirement Obligations); 
+• 
+estimated future costs to develop proved properties are added to the full-cost pool for purposes of the DD&A computation. The Company uses assumptions based on the latest geologic, engineering, regulatory and cost data available to it to estimate these amounts. However, the estimates made are subjective and may change over time. The Company’s estimates of future development costs are reviewed at least annually and as additional information becomes available; and 
+• 
+capitalized costs included in the full-cost pool plus estimated future development costs are depleted and charged against earnings using the unit-of-production method. Under this method, the Company estimates the proved reserves quantities at the beginning of each accounting period. For each Mcfe produced during the period, the Company records a depletion charge equal to the amount included in the depletable base (net of accumulated depreciation, depletion and amortization) divided by our estimated net proved reserve quantities. 
+Because the Company uses estimates and assumptions to calculate proved reserves (as discussed below) and the amounts included in the depletable base, our depletion rates may materially change if actual results differ from these estimates. 
+Ceiling Test 
+Under the full cost method of accounting, the Company compares, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved crude oil and natural gas properties net of related deferred taxes. The Company refers to this comparison as a “ceiling test.” If the net capitalized costs of proved crude oil and natural gas properties exceed the estimated discounted (at 10%) future net cash flows from proved reserves, the Company is required to write-down the value of its crude oil and natural gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are based on a twelve-month average pricing assumption and include consideration of existing cash flow hedges. Given the volatility of crude oil and natural gas prices, it is reasonably possible that the Company’s estimates of discounted future net cash flows from proved 
+47 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+Table of Contents 
+crude oil and natural gas reserves could change in the near term. If crude oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of crude oil and natural gas properties could occur in the future. See Notes 2 and 12 for additional information regarding the Company’s crude oil and natural gas properties. 
+Estimating Reserves and Present Value of Estimated Future Net Cash Flows 
+Estimates of quantities of proved crude oil and natural gas reserves, including the discounted present value of estimated future net cash flows from such reserves at the end of each quarter, are based on numerous assumptions, which are likely to change over time. These assumptions include: 
+• 
+the prices at which the Company can sell its crude oil and natural gas production in the future. Crude oil and natural gas prices are volatile, but we are required to assume that they remain constant. In general, higher crude oil and natural gas prices will increase quantities of proved reserves and the present value of estimated future net cash flows from such reserves, while lower prices will decrease these amounts; and 
+• 
+the costs to develop and produce the Company’s reserves and the costs to dismantle its production facilities when reserves are depleted. These costs are likely to change over time. Increases in costs will reduce estimated crude oil and natural gas quantities and the present value of estimated future net cash flows, while decreases in costs will increase such amounts. 
+Changes in these prices and/or costs will affect the present value of estimated future net cash flows more than the estimated quantities of oil and natural gas reserves for the Company’s properties that have relatively short productive lives. 
+In addition, the process of estimating proved crude oil and natural gas reserves requires that the Company’s independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. We have described the risks associated with reserve estimation and the volatility of crude oil and natural gas prices under “Risk Factors.” 
+Sales of crude oil and natural gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. 
+Unproved Properties 
+Costs, including capitalized interest, associated with properties that do not have proved reserves are excluded from the depletable base, and are included in the line item “Unevaluated properties excluded from amortization.” Unproved property costs are transferred to the depletable base when wells are completed on the properties or the properties are sold. In addition, the Company is required to determine whether its unproved properties are impaired and, if so, include the costs of such properties in the depletable base. The Company determines whether an unproved property is impaired by periodically reviewing its exploration program on a property-by-property basis. This determination may require the exercise of substantial judgment by management. 
+Asset Retirement Obligations 
+We are required to record its estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-life assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligation and reported as accretion expense within operating expenses in the Consolidated Statements of Operations. See Note 13 for additional information. 
+Derivatives 
+To manage crude oil and natural gas price risk on a portion of our planned future production, we have historically utilized commodity derivative instruments (including collars, swaps, puts, and other structures) on approximately 50% of our projected production volumes in any given year. We do not use these instruments for trading purposes. Settlement of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other cash or futures index price. 
+Beginning in 2012, we elected to no longer designate derivative contracts executed after January 1, 2012 as accounting hedges under FASB ASC 815-20-25. As such and beginning with derivative contracts executed during 2012, all derivative positions are carried at their fair value on the balance sheet and are marked-to-market through earnings at the end of each period. Realized gains (losses) related to cash settlements on these contracts are recorded in the Statement of Operations as an increase or decrease in crude oil and natural gas sales. Unrealized gains (losses) related to our derivative contracts not designated as accounting hedges 
+48 
+Callon Petroleum Company 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations 
+Table of Contents 
+are recorded in the Statement of Operations as an increase or decrease in Unrealized gains (losses) on mark-to-market derivative instruments. 
+Derivative contracts that existed at and prior to December 31, 2011 were accounted for as cash flow hedges, and were recorded at fair market value on its consolidated balance sheet. Changes in fair value were recorded through other comprehensive income (loss), net of tax, in stockholders’ equity. The changes in fair value related to ineffective derivative contracts are recognized as derivative expense (income). The estimated fair value of our derivative contracts is based upon closing exchange prices on NYMEX and in the case of collars and floors, the time value of options. For additional information regarding derivatives and their fair values, see Notes 6 and 7 to the Consolidated Financial Statements and Part II, Item 7A Commodity Price Risk. 
+Income Taxes 
+The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing crude oil and natural gas prices). See Note 11 for additional information regarding Income Taxes. 
+Recent Accounting Standards 
+Various accounting standards and interpretations were issued in 2012 with effective dates subsequent to December 31, 2012 . We have evaluated the recently issued accounting pronouncements that are effective in 2013 and believe that none of them will have a material effect on our financial position, results of operations or cash flows when adopted. For a discussion of recently issued accounting standards, see Note 2 to the Consolidated Financial Statements. 
+49 
+Table of Contents 
+ITEM 7A. Quantitative and Qualitative Disclosures about Market Risks 
+Commodity Price Risk 
+The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil and natural gas, which have historically been very volatile due to unpredictable events such as economical growth or retraction, weather and climate, changes in supply and government actions. Crude oil and natural gas price declines and volatility could adversely affect the Company’s revenues, cash flows and profitability. Price volatility is expected to continue. Using the Company's annual sales volumes for 2012 , excluding the effects of the Company’s hedging program, a 10% decline in the NYMEX price of crude oil and natural gas would have reduced our revenues by approximately $9.1 million and $1.3 million , respectively. 
+While the Company does not enter into derivative transactions for speculative purposes, in order to limit its exposure to this risk, the Company sometimes utilizes price "collars," swaps, puts and other structures to reduce the risk of changes in crude oil and natural gas prices. Under a collar arrangements, no payments are due by either party as long as the market price is above the floor price and below the ceiling price set in the collar. If the price falls below the floor, the counterparty to the collar pays the difference to Callon, and if the price rises above the ceiling, Callon pays the difference to the counterparty. Fixed price “swaps” reduce the Company's exposure to decreases in commodity prices, while simultaneously limiting the benefit the Company might otherwise have received from any increases in commodity prices. The Company’s derivatives policy also allows Callon to, at its discretion, purchase or sale “puts.” Purchased "puts" reduce the Company's exposure to decreases in prices of the hedged commodity while allowing realization of the full benefit from any increases those prices. If the commodity price falls below the "put" price, the counter-party pays the difference to Callon. Conversely, sold "puts" expose the Company to risk whereby Callon would pay its counter-party if prices fall below the "put" price. See Note 6 to the Consolidated Financial Statements for a description of our hedged position at December 31, 2012 . 
+Interest Rate Risk 
+On December 31, 2012 , the majority of the Company's debt consisted of its fixed-rate 13% Senior Notes. However, the Company’s Credit Facility with Regions Bank includes a variable interest rate, and as such fluctuates based on short-term interest rates. Although the Company had $10 million borrowings outstanding at December 31, 2012 under its Credit Facility, were the Company to fully draw its available $65 million borrowing base at the beginning of the year, a 100 basis point change in the variable interest rate would increase the Company’s annual interest expense by $0.65 million. For additional information, see Note 5 to the Consolidated Financial Statements additional information regarding the Company’s Credit Facility and other borrowings at December 31, 2012 . 
+50 
+Table of Contents 
+ITEM 8. Financial Statements and Supplementary Data 
+Page 
+Report of Independent Registered Public Accounting Firm 
+52 
+Consolidated Balance Sheets as of December 31, 2012 and 2011 
+53 
+Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 201 2 
+54 
+Consolidated Statements of Comprehensive Income (Loss) for the Three Years in the Period Ended December 31, 2012 
+55 
+Consolidated Statements of Stockholders' Equity (Deficit) for Each of the Three Years in the Period Ended December 31, 201 2 
+56 
+Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 201 2 
+57 
+Notes to Consolidated Financial Statements 
+58 
+51 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+The Board of Directors and Stockholders of 
+Callon Petroleum Company 
+We have audited the accompanying consolidated balance sheets of Callon Petroleum Company as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, stockholders' equity (deficit) and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. 
+We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. 
+In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Callon Petroleum Company as of December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Callon Petroleum Company’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 14, 2013 , expressed an unqualified opinion thereon. 
+/s/Ernst & Young LLP 
+New Orleans, Louisiana 
+March 14, 2013 
+52 
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED BALANCE SHEETS 
+(In thousands, except share data) 
+December, 31 
+2012 
+2011 
+ASSETS 
+Current assets: 
+Cash and cash equivalents 
+$ 
+1,139 
+$ 
+43,795 
+Accounts receivable 
+15,608 
+15,181 
+Fair market value of derivatives 
+1,674 
+2,499 
+Other current assets 
+1,502 
+1,601 
+Total current assets 
+19,923 
+63,076 
+Crude oil and natural gas properties, full-cost accounting method: 
+Evaluated properties 
+1,497,010 
+1,421,640 
+Less accumulated depreciation, depletion and amortization 
+(1,296,265 
+) 
+(1,208,331 
+) 
+Net oil and natural gas properties 
+200,745 
+213,309 
+Unevaluated properties excluded from amortization 
+68,776 
+2,603 
+Total oil and natural gas properties 
+269,521 
+215,912 
+Other property and equipment, net 
+10,058 
+10,512 
+Restricted investments 
+3,798 
+3,790 
+Investment in Medusa Spar LLC 
+8,568 
+9,956 
+Deferred tax asset 
+64,383 
+65,743 
+Other assets, net 
+1,922 
+718 
+Total assets 
+$ 
+378,173 
+$ 
+369,707 
+LIABILITIES AND STOCKHOLDERS' EQUITY 
+Current liabilities: 
+Accounts payable and accrued liabilities 
+$ 
+36,016 
+$ 
+26,057 
+Asset retirement obligations 
+2,336 
+1,260 
+Fair market value of derivatives 
+125 
+— 
+Total current liabilities 
+38,477 
+27,317 
+13% Senior Notes: 
+Principal outstanding 
+96,961 
+106,961 
+Deferred credit, net of accumulated amortization of $17,800 and $13,123, respectively 
+13,707 
+18,384 
+Total 13% Senior Notes 
+110,668 
+125,345 
+Senior secured revolving credit facility 
+10,000 
+— 
+Asset retirement obligations 
+10,965 
+12,678 
+Other long-term liabilities 
+2,092 
+3,165 
+Total liabilities 
+172,202 
+168,505 
+Stockholders' equity: 
+Preferred Stock, $.01 par value, 2,500,000 shares authorized; 
+— 
+— 
+Common Stock, $.01 par value, 60,000,000 shares authorized; 39,800,548 and 39,398,416 shares outstanding at December 31, 2012 and 2011, respectively 
+398 
+394 
+Capital in excess of par value 
+328,116 
+324,474 
+Other comprehensive income 
+— 
+1,624 
+Retained deficit 
+(122,543 
+) 
+(125,290 
+) 
+Total stockholders' equity 
+205,971 
+201,202 
+Total liabilities and stockholders' equity 
+$ 
+378,173 
+$ 
+369,707 
+The accompanying notes are an integral part of these financial statements. 
+53 
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED STATEMENTS OF OPERATIONS 
+(In thousands, except per share amounts) 
+For the year ended December 31, 
+2012 
+2011 
+2010 
+Operating revenues: 
+Crude oil sales 
+$ 
+96,584 
+$ 
+100,962 
+$ 
+65,243 
+Natural gas sales 
+14,149 
+26,682 
+24,639 
+Total operating revenues 
+110,733 
+127,644 
+89,882 
+Operating expenses: 
+Lease operating expenses 
+26,554 
+20,347 
+17,712 
+Depreciation, depletion and amortization 
+49,701 
+48,701 
+31,805 
+General and administrative 
+20,358 
+16,636 
+16,507 
+Accretion expense 
+2,253 
+2,338 
+2,446 
+Acquisition expense 
+— 
+— 
+233 
+Impairment of other property and equipment (See Note 3) 
+1,177 
+— 
+— 
+Total operating expenses 
+100,043 
+88,022 
+68,703 
+Income from operations 
+10,690 
+39,622 
+21,179 
+Other (income) expenses: 
+Interest expense 
+9,108 
+11,717 
+13,312 
+(Gain) loss on early extinguishment of debt 
+(1,366 
+) 
+(1,942 
+) 
+339 
+Gain on acquired assets (See Note 3) 
+— 
+(5,041 
+) 
+— 
+Gain on derivative contracts 
+(1,717 
+) 
+— 
+— 
+Other income, net 
+(79 
+) 
+(1,426 
+) 
+(257 
+) 
+Total other expenses, net 
+5,946 
+3,308 
+13,394 
+Income before income taxes 
+4,744 
+36,314 
+7,785 
+Income tax expense (benefit) 
+2,223 
+(69,283 
+) 
+(174 
+) 
+Income before equity in earnings of Medusa Spar LLC 
+2,521 
+105,597 
+7,959 
+Equity in earnings of Medusa Spar LLC 
+226 
+799 
+427 
+Net income available to common shares 
+$ 
+2,747 
+$ 
+106,396 
+$ 
+8,386 
+Net income per common share: 
+Basic 
+$ 
+0.07 
+$ 
+2.81 
+$ 
+0.29 
+Diluted 
+$ 
+0.07 
+$ 
+2.76 
+$ 
+0.28 
+Shares used in computing net income per common share: 
+Basic 
+39,522 
+37,908 
+28,817 
+Diluted 
+40,337 
+38,582 
+29,476 
+The accompanying notes are an integral part of these financial statements. 
+54 
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATE STATEMENTS OF COMPREHENSIVE INCOME 
+(In thousands) 
+For the year ended December 31, 
+2012 
+2011 
+2010 
+Net income 
+$ 
+2,747 
+$ 
+106,396 
+$ 
+8,386 
+Other comprehensive income (loss): 
+Change in fair value of derivatives designated as accounting hedges 
+(1,624 
+) 
+2,561 
+(1,082 
+) 
+Total other comprehensive income 
+$ 
+1,123 
+$ 
+108,957 
+$ 
+7,304 
+The accompanying notes are an integral part of these financial statements. 
+55 
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) 
+(In thousands) 
+Preferred Stock 
+Common Stock 
+Capital in Excess of Par 
+Accumulated Other Comprehensive Income (Loss) 
+Retained Earnings (Deficit) 
+Total Stockholders' Equity (Deficit) 
+Balance at December 31, 2009 
+$ 
+— 
+$ 
+287 
+$ 
+243,898 
+$ 
+145 
+$ 
+(325,184 
+) 
+$ 
+(80,854 
+) 
+Deconsolidation of subsidiary 
+— 
+— 
+— 
+— 
+85,095 
+85,095 
+Comprehensive income: 
+Net income 
+— 
+— 
+— 
+— 
+8,386 
+Other comprehensive loss 
+— 
+— 
+— 
+(1,082 
+) 
+— 
+Total comprehensive income 
+7,304 
+Shares issued pursuant to employee benefit plans 
+— 
+1 
+192 
+— 
+— 
+193 
+Restricted stock 
+— 
+2 
+4,070 
+— 
+— 
+4,072 
+Balance at December 31, 2010 
+$ 
+— 
+$ 
+290 
+$ 
+248,160 
+$ 
+(937 
+) 
+$ 
+(231,703 
+) 
+$ 
+15,810 
+Comprehensive income: 
+Net income 
+— 
+— 
+— 
+— 
+106,396 
+Other comprehensive income 
+— 
+— 
+— 
+2,561 
+— 
+Total comprehensive income 
+108,957 
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+207 
+— 
+— 
+207 
+Restricted stock 
+— 
+3 
+2,446 
+— 
+— 
+2,449 
+Common stock issued 
+— 
+101 
+73,661 
+— 
+— 
+73,762 
+Reconsolidate subsidiary 
+— 
+— 
+— 
+— 
+17 
+17 
+Balance at December 31, 2011 
+$ 
+— 
+$ 
+394 
+$ 
+324,474 
+$ 
+1,624 
+$ 
+(125,290 
+) 
+$ 
+201,202 
+Comprehensive income: 
+Net income 
+— 
+— 
+— 
+— 
+2,747 
+Other comprehensive loss 
+— 
+— 
+— 
+(1,624 
+) 
+— 
+Total comprehensive income 
+1,123 
+Shares issued pursuant to employee benefit plans 
+— 
+— 
+235 
+— 
+— 
+235 
+Restricted stock 
+— 
+4 
+3,407 
+— 
+— 
+3,411 
+Balance at December 31, 2012 
+$ 
+— 
+$ 
+398 
+$ 
+328,116 
+$ 
+— 
+$ 
+(122,543 
+) 
+$ 
+205,971 
+The accompanying notes are an integral part of these financial statements. 
+56 
+Table of Contents 
+CALLON PETROLEUM COMPANY 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+(In thousands) 
+For the year ended December 31, 
+2012 
+2011 
+2010 
+Cash flows from operating activities: 
+Net income 
+$ 
+2,747 
+$ 
+106,396 
+$ 
+8,386 
+Adjustments to reconcile net income to 
+cash provided by operating activities: 
+Depreciation, depletion and amortization 
+51,043 
+49,753 
+32,629 
+Accretion expense 
+2,253 
+2,338 
+2,446 
+Amortization of non-cash debt related items 
+402 
+461 
+397 
+Amortization of deferred credit 
+(3,086 
+) 
+(3,155 
+) 
+(3,670 
+) 
+Equity in earnings of Medusa Spar LLC 
+(226 
+) 
+(799 
+) 
+(427 
+) 
+Deferred income tax expense 
+2,223 
+10,928 
+1,503 
+Valuation allowance 
+— 
+(80,211 
+) 
+(1,503 
+) 
+Unrealized gain on derivative contracts 
+(1,683 
+) 
+— 
+— 
+Impairment of other property and equipment 
+1,176 
+— 
+— 
+Gain on acquired assets 
+— 
+(4,995 
+) 
+— 
+Non-cash gain for early debt extinguishment 
+(1,366 
+) 
+(1,942 
+) 
+339 
+Non-cash expense related to equity share-based awards 
+1,697 
+1,337 
+2,347 
+Change in the fair value of liability share-based awards 
+1,620 
+761 
+760 
+Payments to settle asset retirement obligations 
+(1,314 
+) 
+(2,563 
+) 
+(2,486 
+) 
+Changes in current assets and liabilities: 
+Accounts receivable 
+(883 
+) 
+(3,734 
+) 
+59,527 
+Other current assets 
+100 
+180 
+(209 
+) 
+Current liabilities 
+1,753 
+4,695 
+907 
+Payments to settle vested liability share-based awards 
+(3,383 
+) 
+— 
+— 
+Change in natural gas balancing receivable 
+51 
+252 
+347 
+Change in natural gas balancing payable 
+(102 
+) 
+(115 
+) 
+(300 
+) 
+Change in other long-term liabilities 
+205 
+100 
+(115 
+) 
+Change in other assets, net 
+(1,937 
+) 
+(520 
+) 
+(776 
+) 
+Cash provided by operating activities 
+51,290 
+79,167 
+100,102 
+Cash flows from investing activities: 
+Capital expenditures 
+(133,299 
+) 
+(100,243 
+) 
+(59,908 
+) 
+Acquisitions 
+(2,075 
+) 
+— 
+(995 
+) 
+Proceeds from sale of mineral interests and equipment 
+39,936 
+7,615 
+— 
+Investment in restricted assets related to plugging and abandonment 
+— 
+(150 
+) 
+(375 
+) 
+Distribution from Medusa Spar LLC 
+1,735 
+1,267 
+1,540 
+Cash used in investing activities 
+(93,703 
+) 
+(91,511 
+) 
+(59,738 
+) 
+Cash flows from financing activities: 
+Borrowings on senior secured revolving credit facility 
+53,000 
+— 
+— 
+Payments on senior secured revolving credit facility 
+(43,000 
+) 
+— 
+(10,000 
+) 
+Redemption of remaining 9.75% senior notes 
+— 
+— 
+(16,212 
+) 
+Redemption of 13% senior notes 
+(10,225 
+) 
+(35,062 
+) 
+— 
+Issuance of common stock 
+— 
+73,765 
+— 
+Taxes paid related to exercise of employee stock options 
+(18 
+) 
+— 
+(40 
+) 
+Cash (used in) provided by financing activities 
+(243 
+) 
+38,703 
+(26,252 
+) 
+Net change in cash and cash equivalents 
+(42,656 
+) 
+26,359 
+14,112 
+Cash and cash equivalents: 
+Balance, beginning of period 
+43,795 
+17,436 
+3,635 
+Less: Cash held by subsidiary deconsolidated at January 1, 2010 
+— 
+— 
+(311 
+) 
+Balance, end of period 
+$ 
+1,139 
+$ 
+43,795 
+$ 
+17,436 
+The accompanying notes are an integral part of these financial statements. 
+57 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+Note 
+Description 
+Note 
+Description 
+1. 
+Description of Business and Basis of Presentation 
+9. 
+Share-Based Compensation 
+2. 
+Summary of Significant Accounting Policies 
+10. 
+Equity Transactions 
+3. 
+Global Settlement with Joint Interest Partner 
+11. 
+Income Taxes 
+4. 
+Earnings per Share 
+12. 
+Crude Oil and Natural Gas Properties 
+5. 
+Borrowings 
+13. 
+Asset Retirement Obligations 
+6. 
+Derivative Instruments and Hedging Activities 
+14. 
+Supplemental Crude Oil and Natural Gas Reserve Data (unaudited) 
+7. 
+Fair Value Measurements 
+15. 
+Other 
+8. 
+Employee Benefit Plans 
+16. 
+Summarized Quarterly Financial Information (unaudited) 
+NOTE 1 – Description of Business and Basis of Presentation 
+Callon Petroleum Company is an independent crude oil and natural gas company, which since 1950 has been focused on building reserves and production both onshore and offshore through efficient operations and low finding and development costs. Today, the Company's principal development operations are in the Permian basin in West Texas. The Company's producing assets in the Gulf of Mexico provide significant cash flow to execute Callon's current onshore development operations. Following the December 2012 sale of our deepwater Gulf of Mexico property, discussed later within Note 12 , the Company has one remaining deepwater Gulf of Mexico property, along with several Gulf of Mexico shelf properties, providing cash flow to support Callon's onshore development operations. 
+The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company partially owned by a member of current management. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. 
+The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also includes the subsidiaries Callon Offshore Production, Inc. and Mississippi Marketing, Inc. All intercompany accounts and transactions have been eliminated. Certain prior year amounts have been reclassified to conform to presentation in the current year. To the extent these amounts are material, we have either footnoted them within the Company's disclosures or have noted the items within this footnote. 
+Unless otherwise indicated, all amounts included within the footnotes to the financial statements are presented in thousands, except for share, per-share and per-hedge data. 
+58 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+Correction of an Immaterial Error 
+During the second quarter of 2012, the Company determined that its December 31, 2011 financial statements reflected a misstatement caused by an error in adjusting the Company's deferred tax position at December 31, 2011. Management concluded that the impact of this error was immaterial on the prior reporting period. However, because the adjustment to correct the error in 2012 would have had a material impact on the 2012 financial statements, we corrected the prior period financial statements in the second quarter 2012 Form 10-Q and within the December 31, 2012 Form 10-K in accordance with SEC guidance. The adjustment had no effect on the Company's cash flow, and the information included in this Form 10-K sets forth the effects of this correction on the previously reported Balance Sheet and Income Statement as of and for the year ended December 31, 2011 as follows: 
+Year ended December 31, 2011 
+As Reported 
+Adjustment 
+As Adjusted 
+Balance Sheet: 
+Deferred tax asset 
+$ 
+63,496 
+$ 
+2,247 
+$ 
+65,743 
+Total assets 
+367,460 
+2,247 
+369,707 
+Retained deficit 
+(127,537 
+) 
+2,247 
+(125,290 
+) 
+Total stockholders' equity 
+198,955 
+2,247 
+201,202 
+Total liabilities and stockholders' equity 
+367,460 
+2,247 
+369,707 
+Income Statement: 
+Income tax benefit 
+$ 
+(67,036 
+) 
+$ 
+(2,247 
+) 
+$ 
+(69,283 
+) 
+Net income available to common shares 
+104,149 
+2,247 
+106,396 
+Net income per common share - Basic 
+2.75 
+0.06 
+2.81 
+Net income per common share - Diluted 
+2.70 
+0.06 
+2.76 
+NOTE 2 – Summary of Significant Accounting Policies 
+A. 
+Use of Estimates 
+The preparation of financial statements in conformity with United States generally accepted accounting principles (“US GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 
+B. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. 
+C. 
+Accounts Receivable 
+Accounts receivable consists primarily of accrued crude oil and natural gas production receivables. The balance in the reserve for doubtful accounts netted within accounts receivable was $34 and $36 at December 31, 2012 and 2011 , respectively. During 2012 , 2011 , and 2010 the Company recorded $0 , $(281) and $281 , respectively of bad debt expense in general and administrative expenses. The negative bad debt expense in 2011 relates to the collection of an amount charged to bad debt expense during 2010. 
+D. 
+Revenue Recognition and Natural Gas Balancing 
+The Company recognizes revenue under the entitlement method of accounting. Under this method, revenue is deferred for deliveries in excess of the Company’s net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the lower of cost or market. The revenue we receive from the sale of natural gas liquids is included in natural gas sales. Natural gas balancing receivables were $93 and $144 as of 2012 and 2011 , respectively. Natural gas balancing payables were $653 and $756 as of 2012 and 2011 , respectively. 
+59 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+E. 
+Major Customers 
+The Company’s production is generally sold on month-to-month contracts at prevailing prices. The following table identifies customers to whom it sold a significant percentage (>10%) of its total crude oil and natural gas production during each of the years ended: 
+December 31, 
+2012 
+2011 
+2010 
+Shell Trading Company 
+39 
+% 
+45 
+% 
+44 
+% 
+Plains Marketing, L.P. 
+15 
+% 
+17 
+% 
+20 
+% 
+Enterprise Crude Oil, LLC 
+32 
+% 
+16 
+% 
+— 
+% 
+Louis Dreyfus Energy Services 
+2 
+% 
+4 
+% 
+13 
+% 
+Other 
+12 
+% 
+18 
+% 
+23 
+% 
+Total 
+100 
+% 
+100 
+% 
+100 
+% 
+Because alternative purchasers of crude oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on its ability to market future crude oil and natural gas production. 
+F. 
+Crude Oil and Natural Gas Properties 
+The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities. The Company capitalized $13,331 , $11,857 and $11,829 of these internal costs during 2012 , 2011 and 2010 , respectively. 
+When applicable, proceeds from the sale or disposition of crude oil and natural gas properties are accounted for as a reduction to capitalized costs unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized in income. 
+Costs of crude oil and natural gas properties, including future development costs, which have proved reserves and properties which have been determined to be worthless, are depleted using the unit-of-production method based on proved reserves. Excluded from this amortization are costs associated with unevaluated properties, including capitalized interest on such costs. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or management determines that these costs have been impaired. 
+Under the SEC's full cost accounting rules, we review the carrying value of our crude oil and natural gas properties each quarter. Under these rules, we compare the present value, discounted at 10%, of estimated future net cash flows from proved crude oil and natural gas reserves to the capitalized costs of crude oil and natural gas properties (net of accumulated depreciation, depletion and amortization and related deferred income taxes) which may not exceed a “ceiling”. 
+These rules generally require that we price our future crude oil and natural gas production at the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. Our reference prices are the West Texas Intermediate, or WTI, for crude oil and the Henry Hub spot price for natural gas. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. The reserve estimates exclude the effect of any derivatives we have in place. The rules require an impairment if our capitalized costs exceed this “ceiling”. See Notes 12 and 14 for additional information regarding the Company’s crude oil and natural gas properties. 
+Upon the acquisition or discovery of crude oil and natural gas properties, the Company estimates by using available geological, engineering and regulatory data the future net costs to dismantle, abandon and restore the property. Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with asset retirement obligation guidance issued by the FASB, such costs are capitalized to the full-cost pool when the related liabilities are incurred. In accordance with SEC's rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part of the costs subject 
+60 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+to the full-cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full-cost ceiling amount. 
+G. 
+Other Property and Equipment 
+The Company depreciates its other property and equipment of $6,424 and $3,998 at December 31, 2012 and 2011 , respectively, using the straight-line method over estimated useful lives of three to 20 years. Depreciation expense of $760 , $645 and $446 relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operations for the years ended December 31, 2012 , 2011 and 2010 , respectively. The accumulated depreciation on other property and equipment was $13,238 and $12,688 as of December 31, 2012 and 2011 , respectively. Included within the Company's other property and equipment, and excluded from depreciation, are certain assets held for sale, which were valued at $3,634 and $6,514 as of December 31, 2012 and 2011 , respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist. See Note 7 for additional information regarding the assets held for sale and their fair values. 
+H. 
+Asset Retirement Obligations 
+The Company is required to record its estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the consolidated statements of operations. See Note 13 for additional information. 
+I. 
+Derivatives 
+The Company’s derivative contracts executed prior to 2012 were designated as cash flow hedges, and were recorded at fair market value with the changes in fair value recorded net of tax through other comprehensive income (loss) (“OCI”) in stockholders’ equity. Ineffective derivative contracts or portions of contract designated as cash flow hedges are recognized as derivative expense (income). The last of the Company's derivative contracts designated as cash flow hedges expired on December 31, 2012. Derivative contracts executed during 2012 and outstanding as of December 31, 2012 are not designated as accounting hedges, and are also carried on the balance sheet at their fair market value. Changes in the fair value of derivative contracts not designated as accounting hedges are reflected in earnings as a gain or loss on derivative contracts. See Notes 6 and 7 for additional information regarding the Company's derivative contracts. 
+J. 
+Income Taxes 
+Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for crude oil and natural gas properties for financial reporting purposes and income tax purposes. US GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforward and tax credit carryforwards, net of a valuation allowance. A valuation allowance is provided for that portion of the asset for which it is deemed more likely than not will not be realized. See Note 11 for additional information. 
+K. 
+Share-Based Compensation 
+The Company grants to directors and employees stock options, restricted stock awards ("RS awards"), and restricted stock unit awards ("RSU awards") that may be settled in cash or common stock at the option of the Company and RSU awards that may only be settled in cash (“Cash-settleable RSU awards”). 
+Stock Options. For stock options the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years). 
+RS awards, RSU awards and Cash-settleable RSU awards. For RS and RSU awards that the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years). For Cash-settleable RSU awards that the Company expects or is required to settle in cash, share-based compensation expense is based on the fair value remeasured at each reporting period, recognized over the vesting period (generally three years) and classified as Accounts payable and accrued liabilities for the portion of the awards that are vested or are expected to vest within the next 12 months, with the remainder classified as Other long-term liabilities . 
+61 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+L. 
+Statements of Cash Flows 
+During the three year period ended 2012 , the Company paid no federal income taxes. During the years ended December 31, 2012 , 2011 and 2010 , the company made cash interest payments of $13,920 , $14,922 and $18,579 , respectively. 
+M. 
+Off-Balance Sheet Investment in Medusa Spar LLC 
+The Company holds a 10% ownership interest in Medusa Spar LLC (“LLC”), which is accounted for under the equity method of accounting for investments. The LLC owns a 75% undivided ownership interest in the deepwater spar production facilities at the Company’s Medusa field in the Gulf of Mexico. The LLC earns a tariff based upon production volume throughput from the Medusa area. Callon is obligated to process through the spar production facilities its share of production from the Medusa field and any future discoveries in the area. The balance of Medusa Spar LLC is owned by Oceaneering International, Inc. and Murphy Oil Corporation. 
+N. 
+Consolidation of Variable Interest Entities 
+In June 2009, the FASB issued an accounting standard which became effective for the Company on January 1, 2010, and which amended US GAAP as follows: 
+• 
+to require an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a Variable Interest Entity (“VIE”), identifying the primary beneficiary of a VIE; 
+• 
+to require ongoing reassessment of whether an enterprise is the primary beneficiary of a VIE, rather than only when specific events occur; 
+• 
+to eliminate the quantitative approach previously required for determining the primary beneficiary of a VIE; 
+• 
+to amend certain guidance for determining whether an entity is a VIE; 
+• 
+to add an additional reconsideration event when changes in facts and circumstances pertinent to a VIE occur; 
+• 
+to eliminate the exception for troubled debt restructuring regarding VIE reconsideration; and 
+• 
+to require advanced disclosures that will provide users of financial statements with more transparent information about an enterprise’s involvement in a VIE. 
+The Company adopted the pronouncement for consolidation of variable interest entities on January 1, 2010. Upon adoption, and as discussed in Note 3 , the Company reevaluated its interest in its subsidiary, Callon Entrada. Based on the evaluation performed, management concluded that a VIE reconsideration event had taken place resulting in the determination that Callon Entrada is a VIE, for which the Company is not the primary beneficiary. Therefore, effective January 1, 2010, Callon Entrada was deconsolidated from the consolidated financial statements of the Company. During the second quarter of 2011 and through the formal execution of a wind-down agreement with its former joint interest partner in the Entrada deepwater project, the Company became the primary beneficiary of Callon Entrada. Consequently, effective April 29, 2011, Callon Entrada was reconsolidated in the Company's financial statements. For additional information, see Note 3 . 
+O. 
+Earnings per Share ("EPS") 
+The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS reflects the potential dilution, using the treasury-stock method, which assumes that options were exercised and restricted stock was fully vested. Diluted EPS also includes the impact of unvested share appreciation plans. For awards in which the share price goals have already been achieved, shares are included in diluted EPS using the treasury-stock method. For those awards in which the share price goals have not been achieved, the number of contingently issuable shares included in the diluted EPS is based on the number of shares, if any, using the treasury-stock method, that would be issuable if the market price of the Company’s stock at the end of the reporting period exceeded the share price goals under the terms of the plan. 
+P. 
+Treasury Stock 
+The Company applies the weighted-average-cost method of accounting for treasury stock transactions and held 29 treasury shares as of December 31, 2012 . 
+62 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+Q. 
+Recent Accounting Pronouncements 
+From time to time, new accounting pronouncements are issued by FASB that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption. 
+NOTE 3 - Global Settlement with Joint Interest Partner 
+During May 2011, the Company entered into a final project wind-down agreement (the "Agreement") with CIECO. As a result of this Agreement, which included both the assignment of the rights to the Entrada assets (including the rights to 50% of the assets previously held by CIECO and the rights to 50% of the assets held by Callon Entrada) and the proceeds from the ultimate sale of such assets, the Company gained the power to direct the activities related to the sale of the remaining assets, and therefore became the primary beneficiary of Callon Entrada. Therefore, Callon Entrada was consolidated in the Company's consolidated financial statements, effective April 29, 2011. Upon consolidating Callon Entrada, the Company estimated the fair values of the assets acquired to be $11,349 and liabilities assumed, primarily deferred tax liabilities associated with the tax basis difference in the assets, of Callon Entrada to be $2,681 as a result of this Agreement. Also in connection with this Agreement, Callon Entrada agreed to pay to CIECO approximately $438 , which represented the net balance of joint interest billings due to CIECO and which had been previously accrued. The agreement also included joint releases of each party from any further liabilities or obligations to the other party in connection with the Entrada project. The adjusted fair market value of the net assets acquired of approximately $8,759 were recorded during 2011 as a $5,041 gain and $3,718 as an adjustment to the Company's full cost pool of crude oil and natural gas properties. 
+While the Company continues to actively market these assets, its inability to complete a transaction over the past several quarters constituted an impairment indicator, which prompted the Company to reevaluate the remaining value of the assets. As of December 31, 2012 , the remaining unsold assets, which are included in the Company's balance sheet as a component of Other property and equipment, net had carrying values of $3,634 . During the year ended December 31, 2012, the Company sold assets valued at $527 , and recorded an impairment charge of $1,177 to its Statement of Operations as a result of the Company's December 31, 2012 impairment analysis. The Company continues to actively market these assets, and will continue to monitor the assets for additional impairment. See Note 7 for additional information regarding the determination of the assets' fair values. 
+NOTE 4 - Earnings per Share 
+Basic net income per common share was computed by dividing net income by the weighted average number of shares of common stock outstanding during the year. Diluted net income per common share was determined on a weighted average basis using common shares issued and outstanding adjusted for the effect of stock options and restricted stock considered common stock equivalents computed using the treasury stock method. 
+A reconciliation of the basic and diluted net income per share computation is as follows (in thousands, except per share amounts): 
+For the year ended December 31, 
+2012 
+2011 
+2010 
+(a) Net income 
+$ 
+2,747 
+$ 
+106,396 
+$ 
+8,386 
+(b) Weighted average shares outstanding 
+39,522 
+37,908 
+28,817 
+Dilutive impact of stock options 
+8 
+18 
+108 
+Dilutive impact of restricted stock 
+807 
+656 
+551 
+(c) Weighted average shares outstanding 
+for diluted net income per share 
+40,337 
+38,582 
+29,476 
+Basic net income per share (a/b) 
+$ 
+0.07 
+$ 
+2.81 
+$ 
+0.29 
+Diluted net income per share (a/c) 
+$ 
+0.07 
+$ 
+2.76 
+$ 
+0.28 
+The following were excluded from the diluted EPS calculation because their effect would be anti-dilutive: 
+Stock options 
+52 
+67 
+122 
+Restricted stock 
+123 
+816 
+5 
+63 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+NOTE 5 - Borrowings 
+For the year ended December 31, 
+2012 
+2011 
+Principal components: 
+Credit Facility 
+$ 
+10,000 
+$ 
+— 
+13% Senior Notes due 2016, principal 
+96,961 
+106,961 
+Total principal outstanding 
+$ 
+106,961 
+$ 
+106,961 
+Non-cash components: 
+13% Senior Notes due 2016 unamortized deferred credit 
+13,707 
+18,384 
+Total carrying value of borrowings 
+$ 
+120,668 
+$ 
+125,345 
+Senior Secured Revolving Credit Facility (the “Credit Facility”) 
+On June 20, 2012, Regions Bank increased the Company's Credit Facility to $200,000 with an associated borrowing base under the Credit Facility of $60,000 and a maturity of July 31, 2014. In October 2012, the Credit Facility was further amended to increase the borrowing base to $80,000 , extend the maturity to March 15, 2016 and add Citibank, NA, IberiaBank, Whitney Bank and OneWest Bank, FSB as participating lenders. Regions Bank continues to serve as Administrative Agent for the Credit Facility. 
+Following the sale of our interest in the deepwater Habanero field and as of December 31, 2012 , the borrowing base was revised to $65,000 , representing a 44% increase over the $45,000 borrowing base at December 31, 2011 . The $39,410 proceeds from this sale, net of customary purchase price adjustments, were used to reduce outstanding borrowings on the Credit Facility to the $10,000 reflected on the Company's Consolidated Balance Sheet as of December 31, 2012 . 
+Amounts borrowed under the Credit Facility may not exceed a borrowing base, which is generally reviewed on a semi-annual basis and is then eligible for re-determination. The next redetermination is scheduled for the first quarter of 2013, and will be based upon year-end 2012 proved reserves. The Credit Facility is secured by mortgages covering the Company's major producing fields. 
+As of December 31, 2012 , the balance outstanding on the Credit Facility was $10,000 with an interest rate on the Credit Facility of 2.72% , calculated as the London Interbank Offered Rate ("LIBOR"), plus a tiered rate ranging from 2.5% to 3.0% , which is based on the amount drawn on the Credit Facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum on the unused portion of the borrowing base, which is payable quarterly. As of March 13, 2013 , the balance outstanding on the Credit Facility was $25,000 as the Company drew an additional $15,000 in support of the Company's ongoing capital development program. 
+13% Senior Notes due 2016 (“Senior Notes”) and Deferred Credit 
+As of December 31, 2012 , the Company had principal outstanding of $96,961 related to its 13% Senior Notes due 2016. The interest coupon is payable on the last day of each quarter. 
+Upon issuing the Senior Notes during November 2009, the Company reduced the carrying amount of the Old Notes by the fair value of the common and preferred stock issued in the amount of $11,527 . The $31,507 difference between the adjusted carrying amount of the Old Notes and the face value of the Senior Notes was recorded as a deferred credit, which is being amortized as a reduction in interest expense over the life of the Senior Notes at an 8.5% effective interest rate. 
+64 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+The following table summarizes the Company’s deferred credit balance at December 31, 2012 : 
+Gross Carrying Amount 
+Accumulated Amortization 
+Carrying Value 
+Amortization Recorded during Current Year (a) 
+Estimated Annual Amortization Expense Expected to be Recognized in 2013 (b) 
+$31,507 
+$17,800 
+$13,707 
+$4,677 
+$3,300 
+(a) 
+Of the amount recorded as amortization during the current year, $3,086 was recorded as a reduction of interest expense and $1,591 (discussed below) was recorded as a component of the gain on early extinguishment of debt. 
+(b) 
+Deferred credit amortization expected to be recorded as a reduction in interest expense during, 2014 , 2015 and 2016 is $3,592 , $3,910 , and $2,905 , respectively. 
+In June 2012, the Company redeemed $10,000 of its Senior Notes, which resulted in a net $1,366 gain on the early extinguishment of debt. The gain represents the difference between the $10,225 paid (inclusive of $225 of redemption expenses) for Notes with a carrying value of $11,591 (inclusive of the $1,591 of accelerated deferred credit amortization) . 
+Following the completion of an equity offering during February 2011, the Company redeemed $31,000 of the Notes. This redemption was completed in March 2011, and resulted in a gain on the early extinguishment of debt of $1,974 . The gain represents the difference between the $35,062 paid for $37,004 (including $31,000 principal amount of the notes plus $6,004 of accelerated deferred credit amortization) carrying value of the Notes, offset by the $4,030 charge related to the 13% call premium required by the terms of the call option and $32 of redemption expenses. 
+Certain of the Company’s subsidiaries guarantee the Company’s obligations under the Senior Notes. The subsidiary guarantors are 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantors are minor. 
+Restrictive Covenants 
+The Indenture governing our Senior Notes and the Company’s Credit Facility contains various covenants including restrictions on additional indebtedness and payment of cash dividends. In addition, Callon’s Credit Facility contains covenants for maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 2012 . 
+NOTE 6 – Derivative Instruments and Hedging Activities 
+Objectives and Strategies for Using Derivative Instruments 
+The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its crude oil and natural gas production. The Company utilizes primarily collars and swap derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for trading purposes. 
+Counterparty Risk 
+The use of derivative transactions exposes the Company to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. To reduce the Company’s risk in this area, counterparties to the Company’s commodity derivative instruments predominantly include a large, well-known financial institution and/or a large, well-known oil and gas company. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices. 
+The Company executes commodity derivative transactions under master agreements that have netting provisions that provide for offsetting payables against receivables. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a transfer or terminate the arrangement. 
+65 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+Financial statement presentation and settlements 
+Settlements of the Company's derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a New York Mercantile Exchange ("NYMEX") price. The fair value of the Company's derivative instruments, depending on the type of instruments, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. See Note 7 for additional information regarding fair value. 
+During 2012, the Company elected not to designate its derivative contracts, nor does it expect to designate future derivative contracts, as an accounting hedge under FASB ASC 815. Consequently, any derivative contract not designated as an accounting hedge will be carried at its fair value on the balance sheet and marked-to-market at the end of each period, with the change in value reflected as a gain or loss on the statement of operations. 
+Prior to 2012, the Company's derivative contracts recorded on the Consolidated Balance Sheets were designated as cash flow hedges, and were recorded at fair market value with the changes in fair value recorded net of tax through OCI in stockholders' equity. The future cash settlements on effective derivative contracts were recorded as an increase or decrease in crude oil and natural gas sales. Both changes in fair value and cash settlements on effective derivative contracts were recognized as derivative expense (income). 
+The following table reflects the fair values of the Company's derivative instruments for the periods indicated: 
+Balance Sheet Presentation 
+Asset Fair Value 
+Liability Fair Value 
+Net Derivative Fair Value 
+Commodity 
+Classification 
+Line Description 
+12/31/12 
+12/31/11 
+12/31/12 
+12/31/11 
+12/31/12 
+12/31/11 
+Derivatives not designated as Hedging Instruments under ASC 815 
+Natural gas 
+Current 
+Fair market value of derivatives 
+$ 
+— 
+$ 
+— 
+$ 
+(125 
+) 
+$ 
+— 
+$ 
+(125 
+) 
+$ 
+— 
+Natural gas 
+Non-current 
+Other long-term liabilities 
+— 
+— 
+(116 
+) 
+— 
+(116 
+) 
+— 
+Crude oil 
+Current 
+Fair market value of derivatives 
+1,674 
+— 
+— 
+— 
+1,674 
+— 
+Crude oil 
+Non-current 
+Other long-term assets 
+250 
+— 
+— 
+— 
+250 
+— 
+Subtotals 
+$ 
+1,924 
+$ 
+— 
+$ 
+(241 
+) 
+$ 
+— 
+$ 
+1,683 
+$ 
+— 
+Derivatives designated as Hedging Instruments under ASC 815 
+Natural gas 
+Current 
+Fair market value of derivatives 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+Natural gas 
+Non-current 
+Other long-term assets 
+— 
+— 
+— 
+— 
+— 
+— 
+Crude oil 
+Current 
+Fair market value of derivatives 
+— 
+— 
+— 
+2,499 
+— 
+2,499 
+Crude oil 
+Non-current 
+Other long-term liabilities 
+— 
+— 
+— 
+— 
+— 
+— 
+Subtotals 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+2,499 
+$ 
+— 
+$ 
+2,499 
+Totals 
+$ 
+1,924 
+$ 
+— 
+$ 
+(241 
+) 
+$ 
+2,499 
+$ 
+1,683 
+$ 
+2,499 
+66 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+Derivatives not designated as hedging instruments under ASC 815 
+For the periods indicated, the Company recorded the following related to its derivative instruments that were not designated as accounting hedges and are recorded in the Statement of Operations as the gain or loss on derivative contracts: 
+For the year ended December 31, 
+2012 
+2011 
+2010 
+Natural gas derivatives 
+Realized gain, net 
+$ 
+34 
+$ 
+— 
+$ 
+— 
+Unrealized loss, net 
+(241 
+) 
+— 
+— 
+Subtotal loss, net 
+$ 
+(207 
+) 
+$ 
+— 
+$ 
+— 
+Crude oil derivatives 
+Realized gain, net 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+Unrealized gain, net 
+1,924 
+— 
+— 
+Subtotal gain, net 
+$ 
+1,924 
+$ 
+— 
+$ 
+— 
+Total gain on derivative instruments, net 
+$ 
+1,717 
+$ 
+— 
+$ 
+— 
+Derivatives designated as hedging instruments under ASC 815 
+The tables below present the effect of the Company’s derivative financial instruments on the consolidated statements of operations as an increase (decrease) to crude oil and natural gas sales: 
+For the year ended December 31, 
+2012 
+2011 
+2010 
+Amount of gain (loss) reclassified from OCI into income (effective portion) 
+$ 
+1,420 
+$ 
+(375 
+) 
+$ 
+632 
+Amount of gain (loss) recognized in income (ineffective portion and amount excluded from effectiveness testing) 
+— 
+— 
+— 
+Derivative positions 
+Listed in the table below are the outstanding oil and natural gas derivative contracts as of December 31, 2012 : 
+Product 
+Instrument 
+Average Volumes per Month 
+Quantity Type 
+Average Floor Price per Hedge 
+Average Ceiling Price per Hedge 
+Period 
+Crude oil (a) (b) 
+Collar 
+40 
+Bbls 
+$ 
+90.00 
+$ 
+116.00 
+Jan13 - Dec13 
+Product 
+Instrument 
+Average Volumes per Month 
+Quantity Type 
+Put/Call Price 
+Fixed-Price Swap 
+Period 
+Natural gas (c) 
+Swap 
+91 
+MMbtu 
+n/a 
+$ 
+3.52 
+Jan13 - Dec13 
+Natural gas (c) 
+Put Option 
+91 
+MMbtu 
+$ 
+3.00 
+n/a 
+Jan13 - Dec13 
+Natural gas (c) 
+Call Option 
+38 
+MMbtu 
+$ 
+4.75 
+n/a 
+Jan14 - Dec14 
+(a) 
+See "Subsequent Event" discussion below regarding the replacement of this crude oil derivative contract in January 2013. 
+(b) 
+A collar is a combination of a sold call option (ceiling) and a purchased put option (floor). 
+(c) 
+The natural gas swap, put and call option were executed contemporaneously. The "above market" $3.52 /MMbtu swap price the Company received was offset by the value of the two options sold by the Company. The short natural gas put option, when combined with the swap, creates the potential for a reduction in the effective swap price if NYMEX natural gas prices are below $3.00 /MMbtu in 2013. The short natural gas call option, when combined with the Company's long production position, represents a "covered call," and creates a $4.75 /MMbtu ceiling during the covered period. 
+67 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+Subsequent Event: 
+Derivative contracts executed subsequent to December 31, 2012 include the following: 
+Product 
+Instrument 
+Average Volumes per Month 
+Quantity Type 
+Put Price 
+Fixed-Price Swap 
+Period 
+Crude oil (a) 
+Swap 
+40 
+Bbls 
+n/a 
+$ 
+101.30 
+Feb13 - Dec13 
+Crude oil 
+Swap 
+30 
+Bbls 
+n/a 
+$ 
+93.35 
+Jan14 - Dec14 
+Crude oil (a) 
+Put 
+30 
+Bbls 
+$ 
+70.00 
+n/a 
+Jan14 - Dec14 
+(a) 
+During January 2013, the Company monetized the remaining portion (Feb13-Dec13) of its 2013 crude oil collar positions of 40 Bbls per month reflected in previous table. The proceeds from this transaction, combined with the proceeds from the sale of the listed put for 30 Bbls per month, were used to finance the uplift in the crude oil swap for the period Feb13-Dec13. 
+NOTE 7 – Fair Value Measurements 
+Fair value is defined within the accounting rules as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The rules established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels: 
+Level 1 
+Valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and has the highest priority. 
+Level 2 
+Valuations rely on quoted prices in markets that are not active or observable inputs over the full term of the asset or liability. 
+Level 3 
+Valuations are based on prices or third party or internal valuation models that require inputs that are significant to the fair value measurement and are less observable and thus have the lowest priority. 
+Fair Value of Financial Instruments 
+Cash, Cash Equivalents, and Short-Term Investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments. 
+Debt. The Company’s debt is recorded at the carrying amount on its Consolidated Balance Sheet. The fair value of Callon’s fixed-rate debt, which is valued using Level 2 inputs, is based upon estimates provided by an independent investment banking firm. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates. 
+The following table summarizes the respective carrying and fair values at: 
+For the year ended December 31, 
+2012 
+2011 
+Carrying Value 
+Fair Value 
+Carrying Value 
+Fair Value 
+Credit Facility 
+$ 
+10,000 
+$ 
+10,000 
+$ 
+— 
+$ 
+— 
+13% Senior Notes due 2016 (a) 
+110,668 
+100,112 
+125,345 
+110,571 
+Total 
+$ 
+120,668 
+$ 
+110,112 
+$ 
+125,345 
+$ 
+110,571 
+(a) 
+2012 and 2011 Fair value is calculated only in relation to the $96,961 and $106,961 face value outstanding of the 13% Senior Notes, respectively. The remaining $13,707 and $18,384 , respectively represents the Company's deferred credits and have been excluded from the fair value calculation. See Note 5 for additional information. 
+Assets and Liabilities Measured at Fair Value on a Recurring Basis 
+Certain assets and liabilities are reported at fair value on a recurring basis (unless otherwise noted below) in Callon’s Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair values: 
+68 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+Commodity Derivative Instruments. Callon’s derivative policy allows for commodity derivative instruments to consist of collars, natural gas and crude oil basis swaps, and similar commodity instrument structures. The fair value of these derivatives is derived using a valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract, and the values are corroborated by quotes obtained from counterparties to the agreements. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair-value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 6 for additional information regarding the Company’s derivative instruments. 
+The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis for each hierarchy level: 
+December 31, 2012 
+Balance Sheet Presentation 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets 
+Derivative financial instruments - current Portion 
+Fair market value of derivatives 
+$ 
+— 
+$ 
+1,674 
+$ 
+— 
+$ 
+1,674 
+Derivative financial instruments - non-current 
+Other assets, net 
+— 
+250 
+— 
+250 
+Sub-total assets 
+$ 
+— 
+$ 
+1,924 
+$ 
+— 
+$ 
+1,924 
+Liabilities 
+Derivative financial instruments - current portion 
+Fair market value of derivatives 
+$ 
+— 
+$ 
+125 
+$ 
+— 
+$ 
+125 
+Derivative financial instruments - non-current 
+Other long-term liabilities 
+— 
+116 
+— 
+116 
+Sub-total liabilities 
+$ 
+— 
+$ 
+241 
+$ 
+— 
+$ 
+241 
+Total 
+$ 
+— 
+$ 
+1,683 
+$ 
+— 
+$ 
+1,683 
+December 31, 2011 
+Balance Sheet Presentation 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets 
+Derivative financial instruments - current Portion 
+Fair market value of derivatives 
+$ 
+— 
+$ 
+2,499 
+$ 
+— 
+$ 
+2,499 
+Derivative financial instruments - non-current 
+Other assets, net 
+— 
+— 
+— 
+— 
+Total 
+$ 
+— 
+$ 
+2,499 
+$ 
+— 
+$ 
+2,499 
+The derivative fair values above are based on analysis of each contract. Derivative assets and liabilities with the same counterparty are presented here on a gross basis, even where the legal right of offset exists. See Note 6 for a discussion of net amounts recorded in the Consolidated Balance Sheet at December 31, 2012 . 
+Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis 
+Certain assets and liabilities are reported at fair value on a nonrecurring basis in Callon’s Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair values: 
+Asset Retirement Obligations Incurred in Current Period. Callon estimates the fair value of AROs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as (1) the existence of a legal obligation for an ARO, (2) amounts and timing of settlements, (3) the credit-adjusted risk-free rate to be used and (4) inflation rates. AROs incurred for the year ended December 31, 2012 and resulting in fair value measurement, including upward revisions to ARO liabilities of $81 , were Level 3 fair value measurements. See Note 13 for a summary of changes in the Company’s ARO liability. 
+Other Property and Equipment. See Note 3 for additional information regarding the global settlement with Callon’s former joint interest partner on the project. During the second quarter of 2011, Callon acquired 100% of the rights to all remaining assets related to one of the Company's deepwater projects, which primarily consisted of surplus equipment. 
+As Callon is required to measure the assets acquired at fair value, Callon estimated each asset’s fair value based on several factors including (1) historical prices received for assets sold, (2) the similarity of unsold assets to those previously sold and the sales prices for those similar assets, (3) the number of market participants expected to have an interest in the assets, (4) the degree to which the asset has been customized and would require modification by a purchaser for use, and (5) the nature of the asset being 
+69 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+held for sale (i.e. whether the asset is highly specialized, built-for-purpose, etc.). We also obtained certain information that was considered in the valuation of this equipment from an independent firm that is in the business of manufacturing and selling this equipment. 
+Values assigned to equipment sold prior to the June 30, 2011 reporting date and for which the exit price, as defined by US GAAP, became readily determinable, represented Level 2 fair value measurements equal to $3,954 of the total $11,349 acquired through the agreement. The remaining $7,395 of acquired assets represented Level 3 fair value measurements based on the limited ability of market pricing information for either identical or similar items. Certain assets were assigned no value in instances where the fair value was indeterminable due to the built-for-purpose or highly specialized nature of the assets. Also as a result of this settlement agreement, the Company assumed $2,681 of liabilities, which consisted entirely of a deferred tax liability associated with the basis difference of the equipment. 
+At December 31, 2012 , the Company evaluated for impairment the unsold surplus equipment, noting the passage of time without significant sales activity, as an indicator of impairment. The Company followed the process described above to reevaluate the assets fair values. As a result of this analysis, the Company recorded an impairment charge of $1,177 , which was recorded as a loss on the Statement of Operations. T he carrying value of the remaining unsold equipment is $3,634 , at December 31, 2012 , is recorded on the Consolidated Balance Sheet within Other Property and Equipment, net and represents a Level 3 fair value measurement. See Note 3 for additional information. 
+NOTE 8 – Employee Benefit Plans 
+The Company utilizes various forms of incentive compensation designed to align the interest of the executives and employees with those of its stockholders. Tabular disclosures related to the share-based awards are presented in Note 9 . The narrative that follows provides a brief description of each plan, summarizes the overall status of each plan and discusses current year awards under each plan: 
+Savings and Protection Plan 
+The Savings and Protection Plan (“401-K Plan”) provides employees with the option to defer receipt of a portion of their compensation, and the Company may, at its discretion, match a portion of the employee's deferral with cash. The Company may also elect, at its discretion, to contribute a non-matching amount in cash and Company Common Stock to employees. The amounts held under the 401-K Plan are invested in various funds maintained by a third party in accordance with the directions of each employee. An employee is fully vested, including Company discretionary contributions, immediately upon participation in the 401-K Plan. The total amounts contributed by the Company, including the value of the common stock contributed, were $918 , $811 and $690 in the years 2012 , 2011 and 2010 , respectively. 
+2011 Omnibus Incentive Plan (the “2011 Plan”) 
+The 2011 Plan, which became effective May 12, 2011 following shareholder approval, authorized and reserved for issuance 2,300 shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity award that is granted under this plan. The 2011 Plan is the Company's only active plan, and included a provision at inception whereby all remaining, un-issued and authorized shares from the Company's previous share-based incentive plans became issuable under the 2011 Plan. This transfer provision resulted in the transfer of an additional 841 shares into the plan, increasing the quantity authorized and reserved for issuance under the Plan to 3,141 at the inception of the plan. Another provision provided that shares which would otherwise become available for issue under the previous plans as a result of vesting and/or forfeiture of any equity awards existing as of May 12, 2012, would also increase the authorized shares available to the 2011 Plan. As of December 31, 2012 , the 2011 Plan had 1,669 shares remaining and eligible for future issuance. 
+Equity awards issued under this plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. Any vested but unexercised options contractually expire 10 years from the date of grant. Equity awards under the 2011 Plan generally vest over time but may also be subject to attaining a specified performance metrics and may be immediate or cliff vest at a specified date. The Company will recognize expense on the grant date for all immediately vesting awards, while it will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards. For performance-based awards, the Company recognizes expense based on its analysis of the performance criteria, and records or reverses expense as necessary based on its analysis. For market-based awards, the Company recognizes expense based on its analysis of the market criteria, and records expense as necessary based on its analysis. Awards with a market-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest or are awarded. 
+70 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+Stock Incentive Award for Inducement of Employment 
+In April 2012 and as an inducement of employment, the Company awarded 100 restricted stock units to its Senior Vice President of Finance. The restricted stock units vest in one-third increments on each award anniversary date beginning July 1, 2013, and are being expensed ratably over the vesting period. 
+Following the Chief Operating Officer's ("COO") September 2010 departure from the Company, the COO forfeited his previously awarded 200 restricted and performance-based shares and 333 of his unvested performance-based stock options. Prior to his departure in 2010, the Company achieved the first of three performance metrics specified in the performance-based stock options agreement resulting in the COO vesting in 167 options, for which the Company recorded approximately $180 of compensation expense. 
+In April 2010 and as an inducement of employment, the Company awarded 50 restricted stock units to its Senior Vice President of Operations. The restricted stock units cliff vested on January 1, 2011, and were fully expensed as of December 31, 2010. 
+Cash-Settleable RSU Awards 
+Certain of the Company's RSUs awarded require cash-settlement. Cash-settleable RSU awards are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash, and are recorded in the Company's consolidated balance sheet for the ratable portion of their fair values. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense. See Note 7 for additional information regarding fair value of cash-settleable awards. 
+A portion of the Company's cash-settleable RSU awards include a market-based vesting condition and may ultimately vest at a quantity different than the base RSUs awarded. The number of RSUs that cliff-vest is based on a calculation that compares the Company's total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded. As of December 31, 2012 , the Company had the following cash-settleable RSU awards outstanding: 
+Base Units 
+Potential Minimum 
+Potential Maximum 
+Outstanding at 
+Units at Vesting at 
+Units at Vesting at 
+December 31, 2012 
+December 31, 2012 
+December 31, 2012 
+Vesting in 2013 
+348 
+79 
+483 
+Vesting in 2014 
+569 
+62 
+1,077 
+Vesting in 2015 
+72 
+72 
+72 
+Other 
+— 
+— 
+— 
+Total cash-settleable RSU awards 
+989 
+213 
+1,632 
+For the year ended December 31, 2012 , 364 cash-settleable RSUs subject to the peer market-based vesting described above vested at their maximum potential unit vesting of 546 units, resulting in a cash payment of $2,626 . Additionally, 144 cash-settleable RSUs vested during 2012, resulting in a cash payment of $757 . See Note 9 for additional information regarding cash-settleable RSUs. 
+NOTE 9 - Share-Based Compensation 
+As discussed in Note 8 , the Company grants various forms of share-based compensation awards to employees of the Company and its subsidiaries and to non-employee members of the Board of Directors. At December 31, 2012 , shares available for future share-based awards, including stock options or restricted stock grants, under the Company's only active plan, the 2011 Plan, were 1,669 . 
+71 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+The following table presents share-based compensation expense for each respective period: 
+For the year ended December 31, 
+2012 
+2011 
+2010 
+Share-based compensation expense for: 
+Equity-based 
+Liability-based 
+Equity-based 
+Liability-based 
+Equity-based 
+Liability-based 
+Options 
+$ 
+— 
+$ 
+— 
+$ 
+24 
+$ 
+— 
+$ 
+206 
+$ 
+— 
+RSU equity awards 
+4,210 
+— 
+2,832 
+— 
+3,898 
+— 
+Cash-settleable RSU awards 
+— 
+2,916 
+— 
+1,335 
+— 
+1,396 
+401(k) contributions in shares 
+218 
+— 
+202 
+— 
+201 
+— 
+Total share-based compensation expense (a) 
+$ 
+4,428 
+$ 
+2,916 
+$ 
+3,058 
+$ 
+1,335 
+$ 
+4,305 
+$ 
+1,396 
+(a) 
+The portion of this share-based compensation expense that was included in general and administrative expense totaled $4,081 , $2,502 and $3,107 for the same years respectively, and the portion capitalized to oil and gas properties was $3,263 , $1,891 and $2,594 , respectively. 
+The following table presents the specified share-based compensation expense for the indicated periods: 
+As of December 31, 
+Unrecognized compensation costs related to: 
+2012 
+2011 
+2010 
+Unvested options 
+$ 
+— 
+$ 
+— 
+$ 
+57 
+Unvested RSU equity awards 
+6,320 
+5,748 
+3,353 
+Unvested cash-settleable RSU awards 
+2,826 
+2,498 
+2,676 
+Future expected share-based compensation expense for: 
+2013 
+2014 
+2015 
+Thereafter 
+Total 
+RSU equity awards 
+3,565 
+2,182 
+573 
+— 
+6,320 
+Cash-settleable RSU awards 
+1,862 
+937 
+27 
+— 
+2,826 
+The following table summarizes the Company's cash-settleable RSU awards for the periods indicated: 
+Consolidated Balance Sheets Classification 
+2012 
+2011 
+2010 
+Accounts payable and accrued liabilities - current portion 
+$ 
+1,429 
+$ 
+604 
+$ 
+— 
+Other long-term liabilities - non-current portion 
+1,017 
+2,309 
+1,578 
+Total cash-settleable RSU awards 
+$ 
+2,446 
+$ 
+2,913 
+$ 
+1,578 
+Stock Options 
+The Company uses the Black-Scholes option pricing model to estimate the fair value of stock option awards with the following weighted-average assumptions for the indicated periods. However, the Company issued no stock options for the past three years and no options vested during 2012. As of December 31, 2012 , the Company had 67 options outstanding and exercisable at a weighted average exercise price per option of $11.82 , with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 2.7 years. During 2012 , 31 options were exercised at a weighted average exercise price per option of $3.72 and with an aggregate intrinsic value of $56 . Also During 2012, 60 options expired unexercised and 15 options were forfeited. As of December 31, 2011 , the Company had 173 options outstanding and exercisable at a weighted average exercise price per option of $8.66 , with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 2.0 years. The Company net-share settles option exercises and therefore receives no cash proceeds from the exercise of stock options. 
+72 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+Restricted Stock Units 
+The following table represents unvested restricted stock activity for the year ended December 31, 2012 : 
+Weighted average 
+Number of Shares 
+Grant-Date Fair Value per Share 
+Period over which expense is expected to be recognized 
+Outstanding at the beginning of the period 
+1,918 
+$ 
+5.16 
+Granted 
+1,008 
+5.22 
+Vested (a) 
+(530 
+) 
+3.29 
+Forfeited 
+(101 
+) 
+5.88 
+Outstanding at the end of the period 
+2,295 
+$ 
+5.58 
+1.5 
+a. 
+The fair value of shares vested was $2,817 . 
+NOTE 10 – Equity Transactions 
+During February, 2011, the Company received $73,720 in net proceeds from the public offering of 10.1 million shares of its common stock, which included the issuance of 1.1 million shares pursuant to the underwriters' over-allotment option. The Company used $35,062 of the proceeds to repurchase $31,000 principal amount of its Senior Notes, with the remaining proceeds intended for general corporate purposes including the planned development of the Company's Permian basin and other onshore assets. The Company completed the redemption in March 2011, which resulted in a gain on the early extinguishment of debt of $1,974 . The gain represents the difference between the $35,062 paid for the $37,004 (including the $31,000 principal amount of the notes plus $6,004 of accelerated deferred credit amortization) carrying value of the Notes, offset by the $4,030 charge related to the 13% call premium required by the terms of the call option and $32 of redemption expenses. 
+NOTE 11 – Income Taxes 
+The following table presents Callon’s net tax benefits relating to its reported net losses and other temporary differences from operations: 
+For the year ended December 31 
+2012 
+2011 
+Deferred tax asset: 
+Federal net operating loss carryforward 
+$ 
+87,774 
+$ 
+89,457 
+Statutory depletion carryforward 
+8,184 
+7,032 
+Alternative minimum tax credit carryforward 
+208 
+208 
+Asset retirement obligations 
+3,357 
+3,552 
+Other 
+9,571 
+9,182 
+Total deferred tax asset 
+109,094 
+109,431 
+Deferred tax liability: 
+Crude oil and natural gas properties 
+41,336 
+40,782 
+Other 
+3,375 
+2,906 
+Total deferred tax liability 
+44,711 
+43,688 
+Net deferred tax asset 
+$ 
+64,383 
+$ 
+65,743 
+Prior to 2012, the Company carried a full valuation allowance against its net deferred tax assets. The Company considered both the positive and negative evidence in determining whether it was more likely than not that its deferred tax assets were recoverable. The Company incurred a loss in 2008, primarily as a result of a write-down of its crude oil and natural gas properties following the ceiling test, which created a loss on an aggregate basis for the three -year period ended December 31, 2008. Primarily as a result of recent cumulative losses, the Company established a full valuation allowance as of December 31, 2008, and continued to carry the full valuation allowance each reporting period until December 31, 2011. 
+73 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+The Company reported profitable operations from 2009 to 2012, and had income on an aggregate basis for the three -year periods ended December 31, 2011 and 2012. After considering all available positive and negative evidence, the Company believed that it was more likely than not that it would fully utilize its deferred tax assets recorded at December 31, 2011 and 2012. Among other factors, the Company believed its recent cumulative income, together with its future operating results using current proved reserves, provided sufficient positive evidence to reach this conclusion. Based upon this analysis, the Company reversed its related valuation allowance at December 31, 2011. 
+If not utilized, the Company’s federal operating loss ("NOL") carryforwards will expire as follows: 
+Year Expiring 
+Total 
+2013-2018 
+2019-2021 
+2022-2024 
+2025-2027 
+2028-2031 
+Federal NOL carryforwards 
+$ 
+250,783 
+$ 
+— 
+$ 
+56,929 
+$ 
+101,495 
+$ 
+39,714 
+$ 
+52,645 
+The Company has limited state taxable income. Accordingly, the Company has established a full valuation allowance on the tax benefit associated with the state net operating loss carryforwards of approximately $169,672 which expire in years through 2032, as the Company does not anticipate generating taxable state income in the states in which these carryforwards apply. These amounts are not included in the deferred tax summary table above. 
+In 2009, the Company began to shift its operational focus from exploration, development and production in the Gulf of Mexico to the acquisition and development of onshore properties. This shift in exploration and development activity resulted in an increase in Texas income from production by the end of 2012 . This, coupled with the sale of one of the Company's primary federal offshore producing properties, the Habanero field, in December 2012, results in a change in the projected future Texas state tax rate beyond 2012 as a component of overall anticipated future taxes. 
+The Company had no significant unrecognized tax benefits at December 31, 2012 . Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. Tax periods for years 2000 through 2012 remain open to examination by the federal and state taxing jurisdictions to which the Company is subject. 
+In addition, the NOL carryback provision of the Internal Revenue Code was amended on November 6, 2009, as part of The Worker, Homeownership and Business Assistance Act of 2009 (the “WHB Act”). The WHB Act allows businesses with NOLs for 2008 and 2009 to carry back losses for up to five years and suspends the 90% limitation on the use of any alternative minimum tax NOL deduction attributable to carrybacks of the applicable NOL. There would be no limit on the NOL carrybacks for the first four preceding years of the carryback period, but for the fifth preceding year, the NOL carryback would be limited to fifty percent of a company’s taxable income in that year. In applying the new five-year NOL carryback rule, the Company was able to file during 2010 for a refund claim to recover approximately $174 . 
+74 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+Below is a reconciliation of the reported amount of income tax expense attributable to continuing operations to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations. 
+For the years ended December 31, 
+Component of Income Tax Rate Reconciliation 
+2012 
+2011 
+2010 
+Income tax expense computed at the statutory federal income tax rate 
+35 
+% 
+35 
+% 
+35 
+% 
+Change in valuation allowance 
+— 
+% 
+(227 
+)% 
+(18 
+)% 
+Percentage depletion carryforward 
+(22 
+)% 
+(3 
+)% 
+(15 
+)% 
+State taxes net of federal benefit 
+6 
+% 
+— 
+% 
+— 
+% 
+Section 162m 
+22 
+% 
+— 
+% 
+— 
+% 
+Restricted stock and stock options 
+2 
+% 
+— 
+% 
+— 
+% 
+Other 
+4 
+% 
+4 
+% 
+— 
+% 
+Effective income tax rate 
+47 
+% 
+(191 
+)% 
+2 
+% 
+For the years ended December 31, 
+Components of Income Tax Expense 
+2012 
+2011 
+2010 
+Current federal income tax benefit 
+$ 
+— 
+$ 
+— 
+$ 
+(174 
+) 
+Current state income tax expense 
+110 
+— 
+— 
+Deferred federal income tax expense 
+1,777 
+13,176 
+1,503 
+Change in deferred rate 
+336 
+— 
+— 
+Valuation allowance 
+— 
+(82,459 
+) 
+(1,503 
+) 
+Total income tax expense (benefit) 
+$ 
+2,223 
+$ 
+(69,283 
+) 
+$ 
+(174 
+) 
+NOTE 12 – Crude Oil and Natural Gas Properties 
+The following table discloses certain financial data relating to the Company's crude oil and natural gas activities, all of which are located in the United States. 
+For the year ended December 31, 
+2012 
+2011 
+2010 
+Capitalized costs incurred: 
+Evaluated Properties- 
+Beginning of period balance 
+$ 
+1,421,640 
+$ 
+1,316,677 
+$ 
+1,593,884 
+Deconsolidation of Subsidiary January 1, 2010 
+— 
+— 
+(364,589 
+) 
+Capitalized G&A 
+12,148 
+11,205 
+10,676 
+Property acquisition costs 
+2,075 
+— 
+— 
+Exploration costs 
+22,703 
+5,473 
+14,739 
+Development costs 
+38,444 
+88,285 
+61,967 
+End of period balance 
+$ 
+1,497,010 
+$ 
+1,421,640 
+$ 
+1,316,677 
+Unevaluated Properties (excluded from amortization): 
+Beginning of period balance 
+$ 
+2,603 
+$ 
+8,106 
+$ 
+25,442 
+Acquisitions 
+29,590 
+2,422 
+1,374 
+Exploration 
+34,674 
+1,372 
+2,187 
+Capitalized interest 
+2,109 
+573 
+2,000 
+Transfers to evaluated 
+(200 
+) 
+(9,870 
+) 
+(22,897 
+) 
+End of period balance 
+$ 
+68,776 
+$ 
+2,603 
+$ 
+8,106 
+Accumulated depreciation, depletion and amortization: 
+Beginning of period balance 
+$ 
+1,208,331 
+$ 
+1,155,915 
+$ 
+1,488,718 
+Provision charged to expense 
+48,524 
+52,416 
+31,786 
+Deconsolidation of Subsidiary January 1, 2010 
+— 
+— 
+(364,589 
+) 
+Sale of mineral interests 
+39,410 
+— 
+— 
+End of period balance 
+$ 
+1,296,265 
+$ 
+1,208,331 
+$ 
+1,155,915 
+75 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+Unevaluated property costs primarily include lease acquisition costs incurred at federal and state lease sales, unevaluated drilling costs, seismic, capitalized interest and certain overhead costs related to exploration and development. Collectively, these costs are excluded from the amortizable evaluated property base, and consisted of $66,173 incurred in 2012 , $841 in 2011 , and $1,762 in 2010 . These costs are directly related to the acquisition and evaluation of unproved properties and major development projects. The excluded costs and related reserves are included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. The Company expects that the majority of these costs will be evaluated over the next three but within five years. The Company’s unevaluated property balance increased by $66,173 to $68,776 at December 31, 2012 compared to December 31, 2011 . A significant portion of this increase relates to the purchase of leases, primarily in the Midland basin and exploration costs associated with evaluating our new acreage. 
+Subsequent to December 31, 2012 and through March 8, 2013 , the Company completed two horizontal exploration wells and two vertical exploration wells and is evaluating the results. The Company also drilled three horizontal wells and had one in progress. 
+Depletion per unit-of-production (Boe) amounted to $31.56 , $26.42 and $19.00 for the years ended December 31, 2012 , 2011 , and 2010 , respectively. Lease operating expense, or production costs, per unit-of-production (Boe) amounted to $16.86 , $11.04 , and $10.58 for the years ended December 31, 2012 , 2011 , and 2010 , respectively. 
+Under the full-cost accounting rules of the SEC, the Company reviews the carrying value of its proved crude oil and natural gas properties each quarter. Under these rules, capitalized costs of crude oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved crude oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full-cost ceiling amount). These rules generally require pricing based on the preceding 12-months’ average crude oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the “ceiling” is exceeded. Given the volatility of crude oil and natural gas prices, it is reasonably possible that the Company’s estimate of discounted future net cash flows from proved crude oil and natural gas reserves could change in the near term. If crude oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of crude oil and natural gas properties could occur in the future. For the years ended December 31, 2012 , 2011 , and 2010 , the Company recorded no impairment charges related to its crude oil and natural gas properties as a result of this calculation. 
+Property Acquisitions and Dispositions 
+Acquisitions: 
+During the first quarter of 2012, the Company acquired approximately 16,233 gross ( 14,653 net) acres in Borden county, which is located in the northern Midland basin. The northern Midland basin has had limited drilling activity compared with the southern Midland basin (where our current production is located), increasing the economic risk related to these drilling activities. The purchase price of $14,538 was funded from existing cash balances. During the third quarter of 2012, we acquired an additional 8,095 gross acres ( 6,964 net) in this area for a total consideration of $4,835 . 
+During the second quarter of 2012, the Company signed a purchase and sale agreement to acquire 2,319 gross ( 1,762 net) acres in southern Reagan county, Texas for a total purchase price of $12,012 , which was financed with a draw on the Credit Facility. The transaction had an effective date of May 1, 2012 and closed on July 5, 2012. 
+Dispositions: 
+Effective December 28, 2012, the Company closed on the sale of its 11.25% working interest in the Habanero field (Garden Banks Block 341). The Company sold its interest in Habanero to Shell Offshore Inc., a subsidiary of Royal Dutch Shell Plc, for an estimated net cash consideration of USD $39,410 after customary purchase price adjustments. As discussed in Note 2, the proceeds from the sale were accounted for as a reduction to capitalized costs as the sale did not significantly alter the relationship between capitalized costs and proved reserves. 
+76 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+NOTE 13 – Asset Retirement Obligations 
+The following table summarizes the activity for the Company’s asset retirement obligations: 
+For the year ended December 31, 
+2012 
+2011 
+Asset retirement obligations at beginning of the period 
+$ 
+13,938 
+$ 
+15,925 
+Accretion expense 
+2,253 
+2,338 
+Liabilities incurred 
+205 
+36 
+Liabilities settled 
+(1,950 
+) 
+(3,797 
+) 
+Revisions to estimate 
+(1,145 
+) 
+(564 
+) 
+Asset retirement obligations at end of period 
+13,301 
+13,938 
+Less: current asset retirement obligations 
+(2,336 
+) 
+(1,260 
+) 
+Long-term asset retirement obligations at the end of the period 
+$ 
+10,965 
+$ 
+12,678 
+Certain of the Company's operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the Consolidated Balance Sheets at December 31, 2012 as long-term restricted investments were $3,798 . These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties. 
+NOTE 14 – Supplemental Crude Oil and Natural Gas Reserve Data (unaudited) ) 
+The Company's proved oil and natural gas reserves at December 31, 2012 , 2011 and 2010 have been estimated by Huddleston & Co., Inc., the Company’s independent petroleum engineers. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions. 
+There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company's oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves. 
+77 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+Estimated Reserves 
+Changes in the estimated net quantities of crude oil and natural gas reserves, all of which are located onshore within the continental United States and offshore within the Gulf of Mexico, are as follows: 
+Reserve Quantities 
+For the year ended December 31, 
+2012 
+2011 
+2010 
+Proved developed and undeveloped reserves: 
+Crude Oil (MBbls): 
+Beginning of period 
+10,075 
+8,149 
+6,479 
+Revisions to previous estimates 
+(488 
+) 
+(110 
+) 
+423 
+Change in ownership 
+— 
+— 
+— 
+Purchase of reserves in place 
+38 
+— 
+— 
+Sale of reserves in place 
+(504 
+) 
+(30 
+) 
+— 
+Extensions and discoveries 
+2,636 
+3,062 
+2,106 
+Production 
+(977 
+) 
+(996 
+) 
+(859 
+) 
+End of period 
+10,780 
+10,075 
+8,149 
+Natural Gas (MMcf): 
+Beginning of period 
+35,118 
+32,957 
+19,103 
+Revisions to previous estimates 
+(10,838 
+) 
+486 
+354 
+Change in ownership 
+— 
+— 
+— 
+Purchase of reserves in place 
+115 
+— 
+— 
+Sale of reserves in place 
+(4,404 
+) 
+(308 
+) 
+— 
+Extensions and discoveries 
+3,350 
+7,064 
+18,392 
+Production 
+(3,588 
+) 
+(5,081 
+) 
+(4,892 
+) 
+End of period 
+19,753 
+35,118 
+32,957 
+Proved developed reserves: 
+Crude Oil (MBbls): 
+Beginning of period 
+5,069 
+4,503 
+4,346 
+End of period 
+4,955 
+5,069 
+4,503 
+Natural Gas (MMcf): 
+Beginning of period 
+11,605 
+12,715 
+12,301 
+End of period 
+10,680 
+11,605 
+12,715 
+MBoe: 
+Beginning of period 
+7,003 
+6,622 
+6,396 
+End of period 
+6,735 
+7,003 
+6,622 
+Proved undeveloped reserves: 
+Crude Oil (MBbls): 
+Beginning of period 
+5,006 
+3,645 
+2,133 
+End of period 
+5,825 
+5,006 
+3,645 
+Natural Gas (MMcf): 
+Beginning of period 
+23,513 
+20,241 
+6,802 
+End of period 
+9,073 
+23,513 
+20,241 
+MBoe 
+Beginning of period 
+8,925 
+7,019 
+3,267 
+End of period 
+7,337 
+8,925 
+7,019 
+Total Proved Reserves: The Company ended 2012 with estimated net proved reserves of 14,072 MBoe, representing a 12% decrease over 2011 year-end estimated net proved reserves of 15,928 MBoe. The decrease is primarily due to the sale of the Company's interest in the Habanero field and the downward revision of our Haynesville Shale undeveloped reserves at year-end 2012, which were reduced due to low natural gas prices. These decreases were partially offset by the Company’s development of a portion of its Permian basin, on which it drilled a total of 27 oil wells during 2012 . 
+Extrapolation of performance history and material balance estimates were utilized by the Company's independent petroleum and geological firm to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing 
+78 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production. 
+Proved Undeveloped Reserves: The Company annually reviews its proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally, reserves for the Company’s onshore properties are booked as PUDs only if the Company has plans to convert the PUDs into proved developed reserves within five years of the date they are first booked as PUDs. The Company's PUDs decreased 18% to 7,337 MBoe from 8,925 MBoe at December 31, 2012 and 2011 , respectively. Additions during the year added 2,344 MBoe to the Company's PUDs, offset by (1) 557 MBoe primarily comprised of transfers to PDPs as a result of our development program, (2) 1,148 MBoe related to the sale of Habanero, and (3) 2,227 MBoe related to reductions in our PUD reserves, primarily related to the Haynesville Shale, by amounts no longer deemed to be economic PUDs at year-end. Of the Company's year-end 2011 PUD reserves, 6% were converted to proved developed producing reserves by year end 2012 , at a total cost of approximately $19 million , net. 
+Of the Company's 2012 PUDs, 1,297 MBoe are attributable to the Company’s offshore properties in the Medusa fields in the Gulf of Mexico. The Company's deepwater PUDs have been classified as PUDs for more than five years, though we expect to develop these PUDs within the next two years. Callon's decision to classify these reserves as PUDs was primarily based on (1) its ongoing development activities in the area, (2) its historical record of completing development of comparable long-term projects, (3) the amount of time which Callon have maintained the leases or booked reserves without significant development activities and (4) the extent to which Callon have followed previously adopted development plans. Callon's discussions with the field's operator have resulted in the modification of certain development plans for Medusa to drill or sidetrack PUDs within a shorter period of time than originally estimated. The Company expects to develop its Medusa PUDs by drilling a new well by the first quarter of 2014. The Company did not convert any offshore, deepwater PUDs to proved developed in 2012 . 
+Standardized Measure 
+The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2012 . You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Prices based on either the preceding 12-months’ average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. The following table summarizes the average 12-month oil and natural gas prices net of differentials for the respective periods: 
+2012 
+2011 
+2010 
+Average 12-month price, net of differentials, per Mcf of natural gas 
+$ 
+4.81 
+$ 
+5.60 
+$ 
+5.10 
+Average 12-month price, net of differentials, per barrel of crude oil 
+94.68 
+98.98 
+78.07 
+Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate. 
+Natural gas production from our deepwater and Permian basin properties has a high BTU content of separator natural gas. The natural gas Mcf prices of $4.81 and $5.60 used in the 2012 and 2011 reserve estimates include adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected oil prices of $94.68 and $98.98 used in the 2012 and 2011 reserve estimates have been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. 
+79 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+Standardized Measure 
+For the year ended December 31, 
+2012 
+2011 
+2010 
+Future cash inflows 
+$ 
+1,115,570 
+$ 
+1,194,079 
+$ 
+804,111 
+Future costs - 
+Production 
+(249,329 
+) 
+(356,653 
+) 
+(277,793 
+) 
+Development and net abandonment 
+(273,817 
+) 
+(268,628 
+) 
+(146,870 
+) 
+Future net inflows before income taxes 
+592,424 
+568,798 
+379,448 
+Future income taxes 
+(55,772 
+) 
+(78,813 
+) 
+(24,719 
+) 
+Future net cash flows 
+536,652 
+489,985 
+354,729 
+10% discount factor 
+(305,504 
+) 
+(219,628 
+) 
+(155,813 
+) 
+Standardized measure of discounted future net cash flows 
+$ 
+231,148 
+$ 
+270,357 
+$ 
+198,916 
+Changes in Standardized Measure 
+For the year ended December 31, 
+2012 
+2011 
+2010 
+Standardized measure at the beginning of the period 
+$ 
+270,357 
+$ 
+198,916 
+$ 
+135,921 
+Sales and transfers, net of production costs 
+(84,044 
+) 
+(107,297 
+) 
+(72,171 
+) 
+Net change in sales and transfer prices, net of production costs 
+47,261 
+125,518 
+126,571 
+Net change due to purchases and sales of in place reserves 
+(35,665 
+) 
+1,275 
+621 
+Extensions, discoveries, and improved recovery, net of future production and development costs incurred 
+53,446 
+22,598 
+23,739 
+Changes in future development cost 
+39,815 
+(83,110 
+) 
+(68,960 
+) 
+Revisions of quantity estimates 
+(77,322 
+) 
+(949 
+) 
+23,295 
+Accretion of discount 
+30,989 
+68,384 
+10,597 
+Net change in income taxes 
+13,969 
+(32,918 
+) 
+(5,170 
+) 
+Changes in production rates, timing and other 
+(27,658 
+) 
+77,940 
+24,473 
+Aggregate change 
+(39,209 
+) 
+71,441 
+62,995 
+Standardized measure at the end of period 
+$ 
+231,148 
+$ 
+270,357 
+$ 
+198,916 
+NOTE 15 – Other 
+Commitments and Contingencies: The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company. 
+The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement polices hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities. 
+Operating Leases: In February 2012, we contracted a drilling rig for a term of two years to support our horizontal drilling program in the Permian basin. The drilling rig was delivered in April 2012, and lease costs recorded during 2012 was $6,609 . Lease payments will approximate $9,235 in 2013 and $2,277 in 2014. The agreement includes early termination provisions that would reduce the minimum rentals under the agreement, assuming the lessor is unable to re-charter the rig and staffing personnel to another lessee, to $5,784 in 2013 and $1,350 in 2014. Should the lessor be able to re-charter the rig, these minimum rentals would be further reduced by the re-chartered lease payments. 
+80 
+Callon Petroleum Company 
+Notes to the Consolidated Financial Statements 
+(All amounts in thousands, except share, per-share and per-hedge data) 
+Table of Contents 
+NOTE 16 – Summarized Quarterly Financial Information (unaudited) 
+2012 
+First Quarter 
+Second Quarter 
+Third Quarter 
+Fourth Quarter 
+Total revenues 
+$ 
+29,294 
+$ 
+25,360 
+$ 
+27,402 
+$ 
+28,677 
+Income from operations 
+2,716 
+2,759 
+2,563 
+2,652 
+Net income (loss) 
+488 
+3,799 
+(1,105 
+) 
+(435 
+) 
+Net income (loss) per common share - basic 
+0.01 
+0.10 
+(0.03 
+) 
+(0.01 
+) 
+Net income (loss) per common share - diluted 
+0.01 
+0.09 
+(0.03 
+) 
+(0.01 
+) 
+2011 
+First Quarter 
+Second Quarter 
+Third Quarter 
+Fourth Quarter 
+Total revenues 
+$ 
+25,449 
+$ 
+36,834 
+$ 
+33,550 
+$ 
+31,811 
+Income from operations 
+5,789 
+14,201 
+10,524 
+9,108 
+Net income (loss) 
+4,164 
+19,877 
+8,406 
+73,949 
+Net income (loss) per common share - basic 
+0.12 
+0.51 
+0.21 
+1.88 
+Net income (loss) per common share - diluted 
+0.12 
+0.50 
+0.21 
+1.85 
+The amounts reported in the table for 2011 have been amended to adjust for the matter discussed in Note 1 . 
+ITEM 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure 
+There have been no disagreements with the independent auditors on any matters of accounting principles or practices, financial statement disclosure, or auditing scope or procedures. 
+ITEM 9A. Controls and Procedures 
+Disclosure Controls and Procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer's management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. The Company's principal executive and principal financial officers have concluded that the Company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) were effective as of December 31, 2012 . 
+Management’s Report on Internal Control over Financial Reporting . Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2012 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission. Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2012 . 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+The Company's independent registered public accounting firm has issued an attestation report regarding its assessment of the Company's internal control over financial reporting as of December 31, 2012 , which follows Part II, Item 9B of this filing. Additionally, the financial statements for each of the years covered in this Annual Report on Form 10-K have been audited by an independent registered public accounting firm, Ernst & Young LLP whose report is presented immediately preceding the Company's financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. 
+81 
+Table of Contents 
+Changes in Internal Control over Financial Reporting. There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+ITEM 9A (T). Controls and Procedures 
+See Item 9A. 
+ITEM 9B. Other Information 
+Submissions of Matters to a Vote of the Security Holders 
+None. 
+82 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+The Board of Directors and Stockholders of 
+Callon Petroleum Company 
+We have audited Callon Petroleum Company's internal control over financial reporting as of December 31, 2012 based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Callon Petroleum Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, Callon Petroleum Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Callon Petroleum Company as of December 31, 2012 and 2011, and the related statements of operations, comprehensive income, cash flow, and changes in stockholders' equity (deficit) for each of the three years in the period ended December 31, 2012, and our report dated March 14, 2013 expressed an unqualified opinion thereon. 
+/s/Ernst & Young LLP 
+New Orleans, Louisiana 
+March 14, 2013 
+83 
+Table of Contents 
+PART III. 
+ITEM 10. Directors, Executive Officers and Corporate Governance 
+For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 16, 2013 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+The Company has adopted a code of ethics that applies to the Company’s chief executive officer, chief financial officer and chief accounting officer. The full text of such code of ethics has been posted on the Company’s website at www.callon.com, and is available free of charge in print to any shareholder who requests it. Request for copies should be addressed to the Secretary at 200 North Canal Street, Natchez, Mississippi 39120. 
+ITEM 11. Executive Compensation 
+For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 16, 2013 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+For information concerning the security ownership of certain beneficial owners and management, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 16, 2013 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ITEM 13. Certain Relationships and Related Transactions and Director Independence 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 16, 2013 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+ITEM 14. Principal Accountant Fees and Services 
+For information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 16, 2013 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 
+84 
+Table of Contents 
+PART IV. 
+ITEM 15. Exhibits 
+Exhibit 
+Description 
+1 
+The following is an index to the financial statements and financial statement schedules that are filed as part of this Form 10-K on p ages 51 through 80 . 
+Report of Independent Registered Public Accounting Firm 
+Consolidated Balance Sheets as of December 31, 2012 and 2011 
+Consolidated Statements of Operations for each of the three years in the period ended December 31, 2012 
+Consolidated Statements of Stockholders' Equity (Deficit) for each of the three years in the Period Ended December 31, 2012 
+Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2012 
+Notes to Consolidated Financial Statements 
+2 
+Schedules other than those listed above are omitted because they are not required, not applicable or the required information is included in the financial statements or notes thereto. 
+3 
+Exhibits 
+2 
+Plan of acquisition, reorganization, arrangement, liquidation or succession* 
+3 
+Articles of Incorporation and Bylaws 
+3.1 
+Certificate of Incorporation of the Company, as amended (incorporated by reference to Exhibit 3.1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039) 
+3.2 
+Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company's Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) 
+3.3 
+Certificate of Amendment to Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039) 
+3.4 
+Certificate of Amendment to the Certificate of Incorporation of the Company 
+(incorporated by reference to Exhibit 3.4 of the Company's Annual Report on Form 10-K for the year ended December 31, 2010, File No. 001-14039) 
+4 
+Instruments defining the rights of security holders, including indentures 
+4.1 
+Specimen Common Stock Certificate (incorporated by reference from Exhibit 4.1 of the Company's Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) 
+4.2 
+Rights Agreement between Callon Petroleum Company and American Stock Transfer & Trust Company, Rights Agent, dated March 30, 2000 (incorporated by reference from Exhibit 99.1 of the Company’s Registration Statement on Form 8-A, filed April 6, 2000, File No. 001-14039) 
+4.3 
+Indenture for the Company’s 13.00% Senior Notes due 2016, dated November 24, 2009, between Callon Petroleum Company, the subsidiary guarantors described therein, Regions Bank and American Stock Transfer & Trust Company (incorporated by reference to Exhibit T3C to the Company’s Form T3, filed November 19, 2009, File No. 022-28916) 
+9 
+Voting trust agreement 
+None 
+10 
+Material contracts 
+10.1 
+Callon Petroleum Company 1994 Stock Incentive Plan (incorporated by reference from Exhibit 10.5 of the Company's Registration Statement on Form 8-B, filed October 3, 1994) 
+10.2 
+Callon Petroleum Company 1996 Stock Incentive Plan as amended on May 9, 2000 (incorporated by reference from Appendix I of the Company’s Definitive Proxy Statement on Schedule 14A, filed March 28, 2000, File No. 001-14039) 
+10.3 
+Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference to Exhibit 10.13 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-14039) 
+85 
+Table of Contents 
+10.4 
+Medusa Spar Agreement dated as of August 8, 2003, among Callon Petroleum Operating Company, Murphy Exploration & Production Company-USA and Oceaneering International, Inc. (incorporated by reference to Exhibit 10.19 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039) 
+10.5 
+Amendment No. 3 to the Callon Petroleum Company 1996 Stock Incentive Plan (incorporated by reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed January 5, 2009, File No. 001-14039) 
+10.6 
+Amendment No. 1 to the Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference from Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed January 5, 2009, File No. 001-14039) 
+10.7 
+Callon Petroleum Company Amended and Restated 2006 Stock Incentive Plan (incorporated by reference from Exhibit 10.3 of the Company’s Current Report on Form 8-K, filed January 5, 2009, File No. 001-14039) 
+10.8 
+Callon Petroleum Company 2009 Stock Incentive Plan effective as of April 30, 2009 (incorporated by reference from Exhibit A to the Company’s Definitive Proxy Statement on Schedule 14A, filed March 30, 2009, File No. 001-14039) 
+10.9 
+Amendment to the Callon Petroleum Company 1996 Stock Incentive Plan effective as of August 7, 2009 (incorporated by reference from Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2009, File No. 001-14039) 
+10.10 
+Callon Petroleum Company 2010 Phantom Share Plan, adopted May 4, 2010 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on May 7, 2010) 
+10.11 
+Form of Callon Petroleum Company Phantom Share Award Agreement, adopted May 4, 2010 (incorporated by reference to Exhibit 10.2 of the Company’s current Report on Form 8-K filed on May 7 , 2010) 
+10.12 
+Deferred Compensation Plan for Outside Directors; Callon Petroleum Company (effective as of January 1, 2011) (incorporated by reference to Exhibit 10.17 of the Company's Annual Report on Form 10-K for the year ended December 31, 2010, File No. 001-14039) 
+10.13 
+Amended and Restated Severance Compensation Agreement, dated as of March 15, 2011 and effective as of January 1, 2011, by and between Fred L. Callon and Callon Petroleum Company (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K filed on March 18, 2011) 
+10.14 
+Form of Amended and Restated Severance Compensation Agreement, dated as of March 15, 2011 and effective as of January 1, 2011, by and between Callon Petroleum Company and its executive officers (incorporated by reference to Exhibit 10.2 of the Company's Current Report on Form 8-K filed on March 18, 2011) 
+10.15 
+Severance Compensation Agreement, dated as of September 21, 2011, by and between Gary A. Newberry and Callon Petroleum Company (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K filed on September 21, 2011) 
+10.16 
+Severance Compensation Agreement, dated as of September 21, 2011, by and between Vince Borrello and Callon Petroleum Company 
+10.17 
+Fourth Amended and Restated Credit Agreement dated as of June 20, 2012, by and among the Company, the "Lenders" described therein, and Regions Bank as the sole arranger and administrative agent (incorporated by reference from Exhibit 10.1 on Form 8-K, filed June 25, 2012, File No. 001-14039) 
+10.18 
+Fourth Amended and Restated Revolving Promissory Note dated June 20, 2012 (incorporated by reference from Exhibit 10.1 on Form 8-K, filed June 25, 2012, File No. 001-14039) 
+10.19 
+Fourth Amended and Restated Guaranty Agreement dated June 20, 2012 (incorporated by reference from Exhibit 10.1 on Form 8-K, filed June 25, 2012, File No. 001-14039) 
+10.20 
+Master Assignment, Agreement and Amendment No. 1 to the Fourth Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.1 on Form 8-K, filed October 16, 2012, File No. 001-14039) 
+10.21 
+Purchase and Sale Agreement by and between Shell Offshore Inc. and Callon Petroleum Operating Company dated as of November 27, 2012. 
+10.22 
+Resignation/Retirement Agreement and Release between Stephen Woodcock and Callon Petroleum Company dated September 7, 2012 (incorporated by reference from Exhibit 10.1 on Form 8-K, filed September 12, 2012, File No. 14039) 
+10.23 
+Callon Petroleum Company 2011 Omnibus Incentive Plan (incorporated by reference from Exhibit A of the Company's Definitive Proxy Statement on Schedule 14A filed March 21, 2011, File No. 14039) 
+11 
+Statement re computation of per share earnings* 
+86 
+Table of Contents 
+12 
+Statements re computation of ratios* 
+13 
+Annual Report to security holders, Form 10-Q or quarterly reports* 
+14 
+Code of Ethics 
+14.1 
+Code of Ethics for Chief Executive Officers and Senior Financial Officers (incorporated by reference to Exhibit 14.1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039) 
+16 
+Letter re change in certifying accountant* 
+18 
+Letter re change in accounting principles* 
+21 
+Subsidiaries of the Company 
+21.1 
+Subsidiaries of the Company 
+22 
+Published report regarding matters submitted to vote of security holders* 
+23 
+Consents of experts and counsel 
+23.1 
+Consent of Ernst & Young LLP 
+23.2 
+Consent of Huddleston & Co., Inc. 
+24 
+Power of attorney* 
+31 
+Rule 13a-14(a) Certifications 
+31.1 
+Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) 
+31.2 
+Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) 
+32 
+Section 1350 Certifications of Chief Executive and Financial Officers pursuant to 
+Rule 13(a)-14(b) 
+99 
+Additional Exhibits 
+99.1 
+Reserve Report Summary prepared by Huddleston and Co. as of December 31, 2012. 
+101 
+Interactive Data Files ** 
+* 
+Not applicable to this filing 
+** 
+Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability. 
+87 
+Table of Contents 
+SIGNATURES 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 
+Date: 
+March 14, 2013 
+/s/ Fred L. Callon 
+Fred L. Callon (principal executive officer, director) 
+Date: 
+March 14, 2013 
+/s/ B. F. Weatherly 
+B. F. Weatherly (principal financial officer, director) 
+Date: 
+March 14, 2013 
+/s/ Rodger W. Smith 
+Rodger W. Smith (principal accounting officer) 
+Date: 
+March 14, 2013 
+/s/ L. Richard Flury 
+L. Richard Flury (director) 
+Date: 
+March 14, 2013 
+/s/ John C. Wallace 
+John C. Wallace (director) 
+Date: 
+March 14, 2013 
+/s/ Anthony J. Nocchiero 
+Anthony J. Nocchiero (director) 
+Date: 
+March 14, 2013 
+/s/ Larry D. McVay 
+Larry McVay (director) 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
+Date: 
+March 14, 2013 
+/s/ B. F. Weatherly 
+B. F. Weatherly, Executive Vice President and 
+Chief Financial Officer (Principal Financial Officer) 
+88
\ No newline at end of file
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+0000928022,CPE,Callon Petroleum Co,10-K,2013-03-14,2012-12-31,2013-03-14T21:05:12.000Z,0000928022-13-000023,cpe-20121231x10k.htm,CALLON PETROLEUM COMPANY FORM 10-K FYE 12-31-2012,16521804,1,0,https://www.sec.gov/Archives/edgar/data/928022/000092802213000023/cpe-20121231x10k.htm,https://www.sec.gov/Archives/edgar/data/928022/000092802213000023/,2012,2012,1
diff --git a/raw/filings/0000928022/2012/0000928022-13-000023/item1.txt b/raw/filings/0000928022/2012/0000928022-13-000023/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0000928022/2012/0000928022-13-000023/item13.txt b/raw/filings/0000928022/2012/0000928022-13-000023/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..d26b26b65a0a0e32d9985d53898329c714007c95
--- /dev/null
+++ b/raw/filings/0000928022/2012/0000928022-13-000023/item13.txt
@@ -0,0 +1,2 @@
+ITEM 13. Certain Relationships and Related Transactions and Director Independence 
+For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 16, 2013 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
\ No newline at end of file
diff --git a/raw/filings/0000928022/2012/0000928022-13-000023/item9a.txt b/raw/filings/0000928022/2012/0000928022-13-000023/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..ffbd850ae393299a41e328ceac1b3158d29dd3f3
--- /dev/null
+++ b/raw/filings/0000928022/2012/0000928022-13-000023/item9a.txt
@@ -0,0 +1,10 @@
+ITEM 9A. Controls and Procedures 
+Disclosure Controls and Procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer's management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. The Company's principal executive and principal financial officers have concluded that the Company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) were effective as of December 31, 2012 . 
+Management’s Report on Internal Control over Financial Reporting . Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2012 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission. Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2012 . 
+Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+The Company's independent registered public accounting firm has issued an attestation report regarding its assessment of the Company's internal control over financial reporting as of December 31, 2012 , which follows Part II, Item 9B of this filing. Additionally, the financial statements for each of the years covered in this Annual Report on Form 10-K have been audited by an independent registered public accounting firm, Ernst & Young LLP whose report is presented immediately preceding the Company's financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. 
+81 
+Table of Contents 
+Changes in Internal Control over Financial Reporting. There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting. 
+ITEM 9A (T). Controls and Procedures 
+See Item 9A.
\ No newline at end of file
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new file mode 100644
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new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391